Compositions and Methods for Breaking Foams and Emulsions

ABSTRACT

Disclosed herein are methods and composition for breaking foam, emulsions, or any combination thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of priority of U.S. ProvisionalApplication No. 62/948,258 filed Dec. 14, 2019, which is incorporatedherein by reference herein in its entirety.

BACKGROUND

Emulsions and foams can be formed during hydrocarbon recovery andprocessing. In the case of emulsions, there is often a desire to breakthese emulsions to separate the hydrocarbon phase for processing and usein downstream applications. Likewise, there is often a need to breakfoams during the course of hydrocarbon recovery and processing. Toaccomplish these ends, improved compositions and methods for breakingfoams and emulsions are needed.

The compositions and methods described herein address these and otherneeds.

SUMMARY

Provided herein are methods and compositions for breaking a foam, anemulsion, or any combination thereof. Methods for breaking a foam, anemulsion, or any combination thereof can comprise contacting the foam,the emulsion, or any combination thereof with a breaking compositioncomprising a partitioning agent. In some embodiments, the partitioningagent can have an octanol/water partition coefficient ([P]) at 25°, andthe log of the partition coefficient at 25° (log[P]) can be from 0.1 to5. In some embodiments, the partitioning agent has a dielectric constantof from 1 to 50.

In some embodiments, the partitioning agent comprises an alcohol, anether, a non-ionic surfactant, or any combination thereof In certainembodiments, the partitioning agent can comprise an alcohol (e.g., abranched C3-C10 alcohol). In some examples, the alcohol can comprisehexanol (e.g., n-hexanol), isopropanol, 2-ethylhexanol (e.g.,2-ethyl-1-hexanol), 4-methyl-2-pentanol (also known as methylisobutylcarbinol), benzyl alcohol, isobutanol, sec-butanol, tert-butanol,pentaerythritol, ethylene glycol, or any combination thereof.

In some embodiments, the partitioning agent can comprise an ether, suchas alkyl ethoxylate. In some examples, the ether can comprise ethyleneglycol butyl ether (EGBE), diethylene glycol monobutyl ether (DGBE),triethylene glycol monobutyl ether (TEGBE), ethylene glycol dibutylether (EGDE), propylene glycol butyl ether, ethylene glycol monophenylether, phenol-2EO, phenol-4EO, phenol-1PO-2EO, phenol-2PO-2EO, or anycombination thereof.

In some embodiments, the partitioning agent can comprise a non-ionicsurfactant, such as an alkyl ethoxylate surfactant.

In some embodiments, the breaking composition can further comprise oneor more defoamers, demulsifiers, or any combination thereof. In someexamples, the one or more defoamers, demulsifiers, or any combinationthereof can comprise an oil-based defoamer, a water-based defoamer, asilicone-based defoamer, an alkyleneoxy-based defoamer, a polyacrylatedefoamer, a ketone-based defoamer, a phenol-formaldehyde resins such asan acid-catalyzed phenol-formaldehyde resin or a base-catalyzedphenol-formaldehyde resin, an epoxy resin, a polyamines such as apolyamine polymers, a polyol, a di-epoxide, a dendrimer, a star polymer,a zwitterionic surfactant, a cationic surfactant, or a combinationthereof.

In some embodiments, the foam, the emulsion, or any combination thereofis present on or within equipment associated with an oil and gasoperation. In some examples, the equipment associated with an oil andgas operation can comprise a vessel, pipeline, holding tank, separator,pipe, wellbore, wellhead, or any combination thereof.

In some examples, the foam, the emulsion, or any combination thereof canbe present in a pipe, in a pipeline, in a wellhead, or any combinationthereof, and the method can comprise injecting the breaking compositioninto the pipe, into the pipeline, into the wellhead or any combinationthereof. In some embodiments, the method comprises continuouslyinjecting the breaking composition. In some embodiments, the methodcomprises one or more discrete injections of the breaking composition.

In some examples, the foam, the emulsion, or any combination thereof canbe present in a pipe, in a pipeline, in a wellhead, or any combinationthereof, and the method can comprise injecting the breaking compositioninto the pipe, into the pipeline, into the wellhead or any combinationthereof. In some embodiments, the method comprises continuouslyinjecting the breaking composition. In some embodiments, the methodcomprises one or more discrete injections of the breaking composition.

In some examples, the foam, the emulsion, or any combination thereof canbe present in a separator, and the method can comprise injecting thebreaking composition into the separator, injecting the breakingcomposition upstream of the separator, injecting the breakingcomposition downstream of the separator, or any combination thereof. Insome embodiments, the method comprises continuously injecting thebreaking composition. In some embodiments, the method comprises one ormore discrete injections of the breaking composition.

In some embodiments, the foam, the emulsion, or any combination thereofcan comprise a produced fluid. In some embodiments, the produced fluidcomprises an aqueous component, a hydrocarbon component, and one or moresurfactants. In some embodiments, the one or more surfactants cancomprise one or more non-ionic surfactants, one or more anionicsurfactants, one or more cationic surfactants, one or more zwitterionicsurfactants, or any combination thereof.

Also provided are breaking compositions for use in breaking foams andemulsions. The breaking compositions can comprise a partitioning agentand one or more defoamers, demulsifiers, or any combination thereof. Thepartitioning agent can have an octanol/water partition coefficient ([P])at 25°, and the log of the partition coefficient at 25° (log[P]) can befrom 0.1 to 5, such as from 0.1 to 3, from 0.1 to 2, from 0.1 to 1.5,from 0.1 to 1, from 0.1 to 0.8, or from 0.1 to 0.7.

The details of one or more embodiments of the disclosure are set forthin the accompanying drawings and the description below. Other features,objects, and advantages of the disclosure will be apparent from thedescription and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 is a graph of the foam reduction versus defoamer concentration(ppm) when added to 0.15% surfactant in injection brine, at 22° C.,using overhead mixer method.

FIG. 2 includes images illustrating the results of a 50/50 blend ofdefoamer 2 and defoamer 1.

FIG. 3 includes images illustrating the results of a 50/50 blend ofdefoamer 2 and 4-methyl 2-pentanol.

FIG. 4 includes images illustrating the results of a 50/50 blend ofdefoamer 1 and 4-methyl 2-pentanol.

FIG. 5 includes images illustrating the results of using differentconcentrations of C9-11-2.5EO as partitioning agent for sample emulsioncompositions including: 0.2% surfactant solution in injection brine and10% oil.

FIG. 6 includes images illustrating the results of using differentconcentrations of C9-11-2.5EO as partitioning agent for sample emulsioncompositions including: 0.2% surfactant solution in injection brine and10% oil at 40° C. The images were taken after 5 minutes.

FIG. 7 is an image illustrating the results of using differentconcentration of C9-11-2.5EO at different temperatures and timeduration.

FIG. 8 is an image illustrating the results of using 0.2% C9-11-2.5EO,0.04% 4-methyl 2-pentanol, and a blend of 0.2% C9-11-2.5EO and 0.04%4-methyl 2-pentanol as partitioning agents, at 71° C. The image wastaken after 5 minutes.

FIG. 9 includes images illustrating the results of using only 0.2%4-methyl 2-pentanol as partitioning agents, at 40° C. The images weretaken after 0, 1, and 3 minutes.

FIG. 10 is an image illustrating the results of using IPA versus4-methyl-2-pentanol as partitioning agents, at 40° C. The images weretaken after 5 minutes.

FIG. 11 includes images illustrating a sample emulsion compositionbefore and after adding defoamer at 40° C.

FIG. 12 includes images illustrating using only different concentration4-methyl-2-pentanol as partitioning agent over time at 71° C.

FIG. 13 is a table of the partitioning agents tested in Example 3.

FIG. 14 includes images illustrating the results of using C9-11-2.5EO aspartitioning agent for sample emulsion compositions including: 0.2%surfactant formulation #1 with 10% oil. The demulsifier was tested atdifferent concentrations and temperatures (40° C. and 73° C.) and imageswere taken after 3 minutes and 5 minutes.

FIG. 15 includes images illustrating the results of using a 0.2% C9-112.5EO, 0.04% 4-Methyl-2-Pentanol and a blend of 0.2% C9-11 2.5EO and0.04% 4-Methyl-2-Pentanol as partitioning agents for a sample emulsioncomposition including 0.2% surfactant formulation #1 with 10% oil.Images were taken after 5 minutes in 40° C. and 73° C. and 60 minutes in40° C.

FIG. 16 includes images illustrating the results of only using 0.2%4-Methyl-2-Pentanol as partitioning agent for a sample emulsioncomposition including 0.2% surfactant formulation #1.

FIG. 17 is an image illustrating the results of comparing IPA versus4-methyl-2-pentanol as partitioning agents in a sample emulsioncomposition including 0.2% surfactant formulation #1.

FIG. 18 includes images illustrating the results of using differentconcentrations of 4-Methyl-2-Pentanol as partitioning agentfor a sampleemulsion composition including 30% oil, 0.2% surfactant formulation #1,brine #1.

FIG. 19 includes images illustrating the field testing results of using4-Methyl-2-Pentanol as partitioning agent in sample emulsion compositionincluding surfactant formulation #1 at different time points.

FIG. 20 includes images illustrating demulsification results using 3000ppm and 5000 ppm EGBE (Ethylene Glycol monobutyl Ether) as thepartitioning agentin a sample emulsion composition including 0.2%surfactant formulation #1, 20% oil at 40° C., and brine #1. The imageswere taken after 2, 10, 20, and 30 minutes.

FIG. 21 is an image illustrating demulsification using 1000 ppm, 3000ppm, and 5000 ppm TEGBE (Triethylene glycol monobutyl Ether) as thepartitioning agentin a sample emulsion composition including 0.2%surfactant formulation #1, 20% oil at 40° C. The image was taken after10 minutes.

FIG. 22 is an image illustrating demulsification results using 1000 ppm,3000 ppm, and 5000 ppm DGBE (Diethylene Glycol Butyl Ether) as thepartitioning agentin a sample emulsion composition including 0.2%surfactant formulation #1, 20% oil at 40° C., and brine #1. The imageswere taken after 10 minutes.

FIG. 23 includes images illustrating demulsification results using 3000ppm and 5000 ppm PGBE (Propylene Glycol Butyl Ether) as the partitioningagentin a sample emulsion composition including 0.2% surfactantformulation #1, 20% oil at 40° C., and brine #1. The images were takenafter 2 and 10 minutes.

FIG. 24 is an image illustrating demulsification results using 5000 ppmEGPhE (Ethylene Glycol Monophenyl Ether) as the partitioning agentin asample emulsion composition including 0.2% surfactant formulation #1,20% oil at 40° C., and brine #1. The images were taken after 10 minutes.

FIG. 25 includes images illustrating demulsification results using 5000ppm phenol-2EO, phenol-4EO, phenol-2PO-2EO, phenol-1PO-2EO, IBA 5EO, andEGBE as partitioning agentsin a sample emulsion composition including0.2% surfactant formulation #1, 20% oil #1 at 40° C., and brine #1. Theimages were taken after 3 minutes.

FIG. 26 is an image illustrating demulsification results using 5000 ppmof PGBE, phenol-4EO, phenol-2PO-2EO, phenol-1PO-2EO, and EGBE aspartitioning agentsin a sample emulsion composition including 0.26%surfactant formulation #2, 20% oil #1 at 40° C. The images were takenafter 10 minutes.

FIG. 27 is an image illustrating demulsification results using 5000 ppmof PGBE, phenol-2PO-2EO, phenol-1PO-2EO, and EGBE as partitioningagentsin a sample emulsion composition including 0.18% surfactantformulation #3, 20% oil #2 at 40° C. The images were taken after 10minutes.

FIG. 28 is an image illustrating demulsification results using 5000 ppmof phenol-2PO-2EO, phenol-1PO-2EO, phenol-4EO, and EGBE as partitioningagents in a sample emulsion composition including 0.18% surfactantformulation #4, 20% oil #3 at 40° C. The images were taken after 10minutes.

FIG. 29 includes images illustrating the improved performance ofdefoamer 3 when 200 ppm EGBE present.

FIG. 30 is an illustration of an example method and system for of usingthe breaking compositions described herein for the production ofhydrocarbons.

FIG. 31 includes tables showing the partition coefficient (logK_(ow)) ofco-solvents in Octanol/water system.

FIG. 32 includes images illustrating results using oleyl alcohol,ethanol, methanol, PEG 400, PEG 200, EGBE, and 4-methyl-2-pentanol aspartitioning agents in a sample emulsion composition includingformulation #3 and 20% oil#3 at 40° C. The images were taken after 2 and10 minutes.

FIG. 33 is a table of the defoamers tested in Example 3.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

Described herein are methods for breaking a foam, emulsion, or anycombination thereof. The methods can comprise contacting the foam,emulsion, or any combination thereof with a breaking composition. Thebreaking composition can comprise a partitioning agent and optionallyone or more defoamers, demulsifiers, or any combination thereof.

Also described are breaking compositions that can comprise apartitioning agent and optionally one or more defoamers, demulsifiers,or any combination thereof.

Definitions

As used in this specification and the following claims, the terms“comprise” (as well as forms, derivatives, or variations thereof, suchas “comprising” and “comprises”) and “include” (as well as forms,derivatives, or variations thereof, such as “including” and “includes”)are inclusive (i.e., open-ended) and do not exclude additional elementsor steps. For example, the terms “comprise” and/or “comprising,” whenused in this specification, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof. Accordingly, these terms are intended to not only cover therecited element(s) or step(s), but may also include other elements orsteps not expressly recited. Furthermore, as used herein, the use of theterms “a” or “an” when used in conjunction with an element may mean“one,” but it is also consistent with the meaning of “one or more,” “atleast one,” and “one or more than one.” Therefore, an element precededby “a” or “an” does not, without more constraints, preclude theexistence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of ±10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) can include 10% and also includes 20%,and includes percentages in between 10% and 20%, unless explicitlystated otherwise herein.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifan item is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the item described by thisphrase could include only a component of type A. In some embodiments,the item described by this phrase could include only a component of typeB. In some embodiments, the item described by this phrase could includeonly a component of type C. In some embodiments, the item described bythis phrase could include a component of type A and a component of typeB. In some embodiments, the item described by this phrase could includea component of type A and a component of type C. In some embodiments,the item described by this phrase could include a component of type Band a component of type C. In some embodiments, the item described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the item described bythis phrase could include two or more components of type A (e.g., A1 andA2). In some embodiments, the item described by this phrase couldinclude two or more components of type B (e.g., B1 and B2). In someembodiments, the item described by this phrase could include two or morecomponents of type C (e.g., C1 and C2). In some embodiments, the itemdescribed by this phrase could include two or more of a first component(e.g., two or more components of type A (A1 and A2)), optionally one ormore of a second component (e.g., optionally one or more components oftype B), and optionally one or more of a third component (e.g.,optionally one or more components of type C). In some embodiments, theitem described by this phrase could include two or more of a firstcomponent (e.g., two or more components of type B (B1 and B2)),optionally one or more of a second component (e.g., optionally one ormore components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the item described by this phrase could include two or moreof a first component (e.g., two or more components of type C (C1 andC2)), optionally one or more of a second component (e.g., optionally oneor more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B).

The term “hydrocarbon” refers to a compound containing only carbon andhydrogen atoms.

“Hydrocarbon-bearing formation” or simply “formation” refers to the rockmatrix in which a wellbore may be drilled. For example, a formationrefers to a body of rock that is sufficiently distinctive and continuoussuch that it can be mapped. It should be appreciated that while the term“formation” generally refers to geologic formations of interest, thatthe term “formation,” as used herein, may, in some instances, includeany geologic points or volumes of interest (such as a survey area).Hydrocarbon-bearing formations can be “unconventional formations” or“conventional formations.”

An “unconventional formation” is a subterranean hydrocarbon-bearingformation that generally requires intervention in order to recoverhydrocarbons from the reservoir at economic flow rates or volumes. Forexample, an unconventional formation includes reservoirs having anunconventional microstructure in which fractures are used to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes(e.g., an unconventional reservoir generally needs to be fractured underpressure or have naturally occurring fractures in order to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes).

In some embodiments, the unconventional formation can include areservoir having a permeability of less than 25 millidarcy (mD) (e.g.,20 mD or less, 15 mD or less, 10 mD or less, 5 mD or less, 1 mD or less,0.5 mD or less, 0.1 mD or less, 0.05 mD or less, 0.01 mD or less, 0.005mD or less, 0.001 mD or less, 0.0005 mD or less, 0.0001 mD or less,0.00005 mD or less, 0.00001 mD or less, 0.000005 mD or less, 0.000001 mDor less, or less). In some embodiments, the unconventional formation caninclude a reservoir having a permeability of at least 0.000001 mD (e.g.,at least 0.000005 mD, at least 0.00001 mD, 0.00005 mD, at least 0.0001mD, 0.0005 mD, 0.001 mD, at least 0.005 mD, at least 0.01 mD, at least0.05 mD, at least 0.1 mD, at least 0.5 mD, at least 1 mD, at least 5 mD,at least 10 mD, at least 15 mD, or at least 20 mD).

The unconventional formation can include a reservoir having apermeability ranging from any of the minimum values described above toany of the maximum values described above. For example, in someembodiments, the unconventional formation can include a reservoir havinga permeability of from 0.000001 mD to 25 mD (e.g., from 0.001 mD to 25mD, from 0.001 mD to 10 mD, from 0.01 mD to 10 mD, from 0.1 mD to 10 mD,from 0.001 mD to 5 mD, from 0.01 mD to 5 mD, or from 0.1 mD to 5 mD).

A “conventional formation” refers to a subterranean hydrocarbon-bearingformation having a higher permeability, such as a permeability of from25 millidarcy to 40,000 millidarcy.

The formation may include faults, fractures (e.g., naturally occurringfractures, fractures created through hydraulic fracturing, etc.),geobodies, overburdens, underburdens, horizons, salts, salt welds, etc.The formation may be onshore, offshore (e.g., shallow water, deep water,etc.), etc. Furthermore, the formation may include hydrocarbons, such asliquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons,any combination of liquid hydrocarbons and gas hydrocarbons (e.g.including gas condensate), etc.

The formation, the hydrocarbons, or both may also includenon-hydrocarbon items, such as pore space, connate water, brine, fluidsfrom enhanced oil recovery, etc. The formation may also be divided upinto one or more hydrocarbon zones, and hydrocarbons can be producedfrom each desired hydrocarbon zone.

The term formation may be used synonymously with the term reservoir. Forexample, in some embodiments, the reservoir may be, but is not limitedto, a shale reservoir, a carbonate reservoir, a tight sandstonereservoir, a tight siltstone reservoir, a gas hydrate reservoir, acoalbed methane reservoir, etc. Indeed, the terms “formation,”“reservoir,” “hydrocarbon,” and the like are not limited to anydescription or configuration described herein.

“Wellbore” refers to a continuous hole for use in hydrocarbon recovery,including any openhole or uncased portion of the wellbore. For example,a wellbore may be a cylindrical hole drilled into the formation suchthat the wellbore is surrounded by the formation, including rocks,sands, sediments, etc. A wellbore may be used for injection. A wellboremay be used for production. A wellbore may be used for hydraulicfracturing of the formation. A wellbore even may be used for multiplepurposes, such as injection and production. The wellbore may havevertical, inclined, horizontal, or any combination of trajectories. Forexample, the wellbore may be a vertical wellbore, a horizontal wellbore,a multilateral wellbore, or slanted wellbore. The wellbore may include a“build section.” “Build section” refers to practically any section of awellbore where the deviation is changing. As an example, the deviationis changing when the wellbore is curving. The wellbore may include aplurality of components, such as, but not limited to, a casing, a liner,a tubing string, a heating element, a sensor, a packer, a screen, agravel pack, etc. The wellbore may also include equipment to controlfluid flow into the wellbore, control fluid flow out of the wellbore, orany combination thereof. For example, each wellbore may include awellhead, a BOP, chokes, valves, or other control devices. These controldevices may be located on the surface, under the surface (e.g., downholein the wellbore), or any combination thereof. The wellbore may alsoinclude at least one artificial lift device, such as, but not limitedto, an electrical submersible pump (ESP) or gas lift. Some non-limitingexamples of wellbores may be found in U.S. Patent ApplicationPublication No. 2014/0288909 (Attorney Dkt. No. T-9407) and U.S. PatentApplication Publication No. 2016/0281494A1 (Attorney Dkt. No. T-10089),each of which is incorporated by reference in its entirety. The termwellbore is not limited to any description or configuration describedherein. The term wellbore may be used synonymously with the termsborehole or well.

The term “enhanced oil recovery” refers to techniques for increasing theamount of unrefined petroleum (e.g., crude oil) that may be extractedfrom an oil reservoir (e.g., an oil field). Using EOR, 40-60% of thereservoir's original oil can typically be extracted compared with only20-40% using primary and secondary recovery (e.g., by water injection ornatural gas injection). Enhanced oil recovery may also be referred to asimproved oil recovery or tertiary oil recovery (as opposed to primaryand secondary oil recovery). Examples of EOR operations include, forexample, miscible gas injection (which includes, for example, carbondioxide flooding), chemical injection (sometimes referred to as chemicalenhanced oil recovery (CEOR), and which includes, for example, polymerflooding, alkaline flooding, surfactant flooding, conformance controloperations, as well as combinations thereof such as alkaline-polymerflooding or alkaline-surfactant-polymer flooding), microbial injection,and thermal recovery (which includes, for example, cyclic steam, steamflooding, and fire flooding). In some embodiments, the EOR operation caninclude a polymer (P) flooding operation, an alkaline-polymer (AP)flooding operation, a surfactant-polymer (SP) flooding operation, analkaline-surfactant-polymer (ASP) flooding operation, a conformancecontrol operation, or any combination thereof. The terms “operation” and“application” may be used interchangeability herein, as in EORoperations or EOR applications.

“Fracturing” is one way that hydrocarbons may be recovered (sometimesreferred to as produced) from the formation. For example, hydraulicfracturing may entail preparing a fracturing fluid and injecting thatfracturing fluid into the wellbore at a sufficient rate and pressure toopen existing fractures and/or create fractures in the formation. Thefractures permit hydrocarbons to flow more freely into the wellbore. Inthe hydraulic fracturing process, the fracturing fluid may be preparedon-site to include at least proppants. The proppants, such as sand orother particles, are meant to hold the fractures open so thathydrocarbons can more easily flow to the wellbore. The fracturing fluidand the proppants may be blended together using at least one blender.The fracturing fluid may also include other components in addition tothe proppants.

The wellbore and the formation proximate to the wellbore are in fluidcommunication (e.g., via perforations), and the fracturing fluid withthe proppants is injected into the wellbore through a wellhead of thewellbore using at least one pump (oftentimes called a fracturing pump).The fracturing fluid with the proppants is injected at a sufficient rateand pressure to open existing fractures and/or create fractures in thesubsurface volume of interest. As fractures become sufficiently wide toallow proppants to flow into those fractures, proppants in thefracturing fluid are deposited in those fractures during injection ofthe fracturing fluid. After the hydraulic fracturing process iscompleted, the fracturing fluid is removed by flowing or pumping it backout of the wellbore so that the fracturing fluid does not block the flowof hydrocarbons to the wellbore. The hydrocarbons will typically enterthe same wellbore from the formation and go up to the surface forfurther processing.

The equipment to be used in preparing and injecting the fracturing fluidmay be dependent on the components of the fracturing fluid, theproppants, the wellbore, the formation, etc. However, for simplicity,the term “fracturing apparatus” is meant to represent any tank(s),mixer(s), blender(s), pump(s), manifold(s), line(s), valve(s), fluid(s),fracturing fluid component(s), proppants, and other equipment andnon-equipment items related to preparing the fracturing fluid andinjecting the fracturing fluid.

Other hydrocarbon recovery processes may also be utilized to recover thehydrocarbons. Furthermore, those of ordinary skill in the art willappreciate that one hydrocarbon recovery process may also be used incombination with at least one other recovery process or subsequent to atleast one other recovery process. Moreover, hydrocarbon recoveryprocesses may also include stimulation or other treatments.

“Fracturing fluid,” as used herein, refers to an injection fluid that isinjected into the well under pressure in order to cause fracturingwithin a portion of the reservoir.

The term “interfacial tension” or “IFT” as used herein refers to thesurface tension between test oil and water of different salinitiescontaining a surfactant formulation at different concentrations.Typically, interfacial tensions are measured using a spinning droptensiometer or calculated from phase behavior experiments.

The term “contacting” as used herein, refers to materials or compoundsbeing sufficiently close in proximity to react or interact. For example,in methods of contacting a foam, an emulsion or any combination thereofwith a breaking composition, the method can include combining the foam,the emulsion or any combination thereof with the breaking compositionany suitable manner known in the art (e.g., pumping, injecting, pouring,releasing, displacing, spotting or circulating the breaking compositioninto a vessel, pipeline, holding tank, separator, pipe, wellbore, orformation containing the foam, the emulsion, or any combinationthereof).

The terms “unrefined petroleum” and “crude oil” are used interchangeablyand in keeping with the plain ordinary usage of those terms. “Unrefinedpetroleum” and “crude oil” may be found in a variety of petroleumreservoirs (also referred to herein as a “reservoir,” “oil fielddeposit” “deposit” and the like) and in a variety of forms includingoleaginous materials, oil shales (i.e., organic-rich fine-grainedsedimentary rock), tar sands, light oil deposits, heavy oil deposits,and the like. “Crude oils” or “unrefined petroleums” generally refer toa mixture of naturally occurring hydrocarbons that may be refined intodiesel, gasoline, heating oil, jet fuel, kerosene, and other productscalled fuels or petrochemicals. Crude oils or unrefined petroleums arenamed according to their contents and origins, and are classifiedaccording to their per unit weight (specific gravity). Heavier crudesgenerally yield more heat upon burning, but have lower gravity asdefined by the American Petroleum Institute (API) (i.e., API gravity)and market price in comparison to light (or sweet) crude oils. Crude oilmay also be characterized by its Equivalent Alkane Carbon Number (EACN).The term “API gravity” refers to the measure of how heavy or light apetroleum liquid is compared to water. If an oil's API gravity isgreater than 10, it is lighter and floats on water, whereas if it isless than 10, it is heavier and sinks. API gravity is thus an inversemeasure of the relative density of a petroleum liquid and the density ofwater. API gravity may also be used to compare the relative densities ofpetroleum liquids. For example, if one petroleum liquid floats onanother and is therefore less dense, it has a greater API gravity.

Crude oils vary widely in appearance and viscosity from field to field.They range in color, odor, and in the properties they contain. While allcrude oils are mostly hydrocarbons, the differences in properties,especially the variation in molecular structure, determine whether acrude oil is more or less easy to produce, pipeline, and refine. Thevariations may even influence its suitability for certain products andthe quality of those products. Crude oils are roughly classified intothree groups, according to the nature of the hydrocarbons they contain.(i) Paraffin-based crude oils contain higher molecular weight paraffins,which are solid at room temperature, but little or no asphaltic(bituminous) matter. They can produce high-grade lubricating oils. (ii)Asphaltene based crude oils contain large proportions of asphalticmatter, and little or no paraffin. Some are predominantly naphthenes andso yield lubricating oils that are sensitive to temperature changes thanthe paraffin-based crudes. (iii) Mixed based crude oils contain bothparaffin and naphthenes, as well as aromatic hydrocarbons. Most crudeoils fit this latter category.

“Reactive” crude oil, as referred to herein, is crude oil containingnatural organic acidic components (also referred to herein as unrefinedpetroleum acid) or their precursors such as esters or lactones. Thesereactive crude oils can generate soaps (carboxylates) when reacted withalkali. More terms used interchangeably for crude oil throughout thisdisclosure are hydrocarbons, hydrocarbon material, or active petroleummaterial. An “oil bank” or “oil cut” as referred to herein, is the crudeoil that does not contain the injected chemicals and is pushed by theinjected fluid during an enhanced oil recovery process. A “nonactiveoil,” as used herein, refers to an oil that is not substantiallyreactive or crude oil not containing significant amounts of naturalorganic acidic components or their precursors such as esters or lactonessuch that significant amounts of soaps are generated when reacted withalkali. A nonactive oil as referred to herein includes oils having anacid number of less than 0.5 mg KOH/g of oil.

“Unrefined petroleum acids” as referred to herein are carboxylic acidscontained in active petroleum material (reactive crude oil). Theunrefined petroleum acids contain C₁₁-C₂₀ alkyl chains, includingnapthenic acid mixtures. The recovery of such “reactive” oils may beperformed using alkali (e.g., NaOH or Na₂CO₃) in a surfactantcomposition. The alkali reacts with the acid in the reactive oil to formsoap in situ. These in situ generated soaps serve as a source ofsurfactants minimizing the levels of added surfactants, thus enablingefficient oil recovery from the reservoir.

The term “polymer” refers to a molecule having a structure thatessentially includes the multiple repetitions of units derived, actuallyor conceptually, from molecules of low relative molecular mass. In someembodiments, the polymer is an oligomer.

The term “solubility” or “solubilization” in general refers to theproperty of a solute, which can be a solid, liquid or gas, to dissolvein a solid, liquid or gaseous solvent thereby forming a homogenoussolution of the solute in the solvent. Solubility occurs under dynamicequilibrium, which means that solubility results from the simultaneousand opposing processes of dissolution and phase joining (e.g.,precipitation of solids). The solubility equilibrium occurs when the twoprocesses proceed at a constant rate. The solubility of a given solutein a given solvent typically depends on temperature. For many solidsdissolved in liquid water, the solubility increases with temperature. Inliquid water at high temperatures, the solubility of ionic solutes tendsto decrease due to the change of properties and structure of liquidwater. In more particular, solubility and solubilization as referred toherein is the property of oil to dissolve in water and vice versa.

“Viscosity” refers to a fluid's internal resistance to flow or beingdeformed by shear or tensile stress. In other words, viscosity may bedefined as thickness or internal friction of a liquid. Thus, water is“thin”, having a lower viscosity, while oil is “thick”, having a higherviscosity. More generally, the less viscous a fluid is, the greater itsease of fluidity.

The term “salinity” as used herein, refers to concentration of saltdissolved in an aqueous phases. Examples for such salts are withoutlimitation, sodium chloride, magnesium and calcium sulfates, andbicarbonates. In more particular, the term salinity as it pertains tothe present invention refers to the concentration of salts in brine andsurfactant solutions.

The term “co-solvent,” as used herein, refers to a compound having theability to increase the solubility of a solute (e.g., a surfactant asdisclosed herein) in the presence of an unrefined petroleum acid. Insome embodiments, the co-solvents provided herein have a hydrophobicportion (alkyl or aryl chain), a hydrophilic portion (e.g., an alcohol)and optionally an alkoxy portion. Co-solvents as provided herein includealcohols (e.g., C₁-C₆ alcohols, C₁-C₆ diols), alkoxy alcohols (e.g.,C₁-C₆ alkoxy alcohols, C₁-C₆ alkoxy diols, and phenyl alkoxy alcohols),glycol ether, glycol and glycerol. The term “alcohol” is used accordingto its ordinary meaning and refers to an organic compound containing an—OH groups attached to a carbon atom. The term “diol” is used accordingto its ordinary meaning and refers to an organic compound containing two—H groups attached to two different carbon atoms. The term “alkoxyalcohol” is used according to its ordinary meaning and refers to anorganic compound containing an alkoxy linker attached to a —OH group

The phrase “surfactant package,” as used herein, refers to one or moresurfactants which are present in a composition.

The term “alkyl,” as used herein, refers to saturated straight,branched, cyclic, primary, secondary or tertiary hydrocarbons, includingthose having 1 to 32 atoms. In some embodiments, alkyl groups willinclude C₁-C₃₂, C₇-C₃₂, C₇-C₂₈, C₁₂-C₂₈, C₁₂-C₂₂, C₁-C₁₂, C₁-C₁₀, C₁-C₈,C₁-C₆, C₁-C₅, C₁-C₄, C₁-C₃, C₁-C₂, or C₁ alkyl groups. Examples ofC₁-C₁₀ alkyl groups include, but are not limited to, methyl, ethyl,propyl, 1-methylethyl, butyl, 1-methylpropyl, 2-methylpropyl,1,1-dimethylethyl, pentyl, 1-methylbutyl, 2-methylbutyl, 3-methylbutyl,2,2-dimethylpropyl, 1-ethylpropyl, hexyl, 1,1-dimethylpropyl,1,2-dimethylpropyl, 1-methylpentyl, 2-methylpentyl, 3-methylpentyl,4-methylpentyl, 1,1-dimethylbutyl, 1,2-dimethylbutyl, 1,3-dimethylbutyl,2,2-dimethylbutyl, 2,3-dimethylbutyl, 3,3-dimethylbutyl, 1-ethylbutyl,2-ethylbutyl, 1,1,2-trimethylpropyl, 1,2,2-trimethylpropyl,1-ethyl-1-methylpropyl, 1-ethyl-2-methylpropyl, heptyl, octyl,2-ethylhexyl, nonyl and decyl groups, as well as their isomers. Examplesof C₁-C₄-alkyl groups include, for example, methyl, ethyl, propyl,1-methylethyl, butyl, 1-methylpropyl, 2-methylpropyl and1,1-dimethylethyl groups.

Cyclic alkyl groups or “cycloalkyl” groups, as used herein, includecycloalkyl groups having from 3 to 10 carbon atoms. Cycloalkyl groupscan include a single ring, or multiple condensed rings. In someembodiments, cycloalkyl groups include C₃-C₄, C₄-C₇, C₅-C₇, C₄-C₆, orC₅-C₆ cyclic alkyl groups. Non-limiting examples of cycloalkyl groupsinclude adamantyl, cyclopropyl, cyclobutyl, cyclopentyl, cyclohexyl,cycloheptyl, cyclooctyl and the like.

Alkyl groups can be unsubstituted or substituted with one or moremoieties selected from the group consisting of alkyl, alkenyl, halo,haloalkyl, hydroxyl, carboxyl, acyl, acyloxy, amino, alkyl- ordialkylamino, amido, arylamino, alkoxy, aryloxy, nitro, cyano, ester,aryl, or any other viable functional group that is permitted by valenceand does not compromise stability.

Terms including the term “alkyl,” such as “alkylcycloalkyl,”“cycloalkylalkyl,” “alkylaryl,” or “arylalkyl,” will be understood tocomprise an alkyl group as defined above linked to another functionalgroup, where the group is linked to the compound through the last grouplisted, as understood by those of skill in the art.

The term “alkenyl,” as used herein, refers to both straight and branchedcarbon chains which have at least one carbon-carbon double bond. In someembodiments, alkenyl groups can include C₂-C₃₂ alkenyl groups. In otherembodiments, alkenyl can include C₇-C₃₂, C₇-C₂₈, C₈-C₂₈, C₁₂-C₂₈, orC₁₂-C₂₂ alkenyl groups. In one embodiment of alkenyl, the number ofdouble bonds is 1-3, in another embodiment of alkenyl, the number ofdouble bonds is one or two. Other ranges of carbon-carbon double bondsand carbon numbers are also contemplated depending on the location ofthe alkenyl moiety on the molecule. “C₂-C₁₀-alkenyl” groups may includemore than one double bond in the chain. The one or more unsaturationswithin the alkenyl group may be located at any position(s) within thecarbon chain as valence permits. In some embodiments, when the alkenylgroup is covalently bound to one or more additional moieties, the carbonatom(s) in the alkenyl group that are covalently bound to the one ormore additional moieties are not part of a carbon-carbon double bondwithin the alkenyl group. Examples of alkenyl groups include, but arenot limited to, ethenyl, 1-propenyl, 2-propenyl, 1-methyl-ethenyl,1-butenyl, 2-butenyl, 3-butenyl, 1-methyl-1-propenyl,2-methyl-1-propenyl, 1-methyl-2-propenyl, 2-methyl-2-propenyl;1-pentenyl, 2-pentenyl, 3-pentenyl, 4-pentenyl, 1-methyl-1-butenyl,2-methyl-1-butenyl, 3-methyl-1-butenyl, 1-methyl-2-butenyl,2-methyl-2-butenyl, 3-methyl-2-butenyl, 1-methyl-3-butenyl,2-methyl-3-butenyl, 3-methyl-3-butenyl, 1,1-dimethyl-2-propenyl,1,2-dimethyl-1-propenyl, 1,2-dimethyl-2-propenyl, 1-ethyl-1-propenyl,1-ethyl-2-propenyl, 1-hexenyl, 2-hexenyl, 3-hexenyl, 4-hexenyl,5-hexenyl, 1-methyl-1-pentenyl, 2-methyl-1pentenyl, 3-methyl-1-pentenyl,4-methyl-1-pentenyl, 1-methyl-2-pentenyl, 2-methyl-2-pentenyl,3-methyl-2-pentenyl, 4-methyl-2-pentenyl, 1-methyl-3-pentenyl,2-methyl-3-pentenyl, 3-methyl-3-pentenyl, 4-methyl-3-pentenyl,1-methyl-4-pentenyl, 2-methyl-4-pentenyl, 3-methyl-4-pentenyl,4-methyl-4-pentenyl, 1,1-dimethyl-2-butenyl, 1,1-dimethyl-3-butenyl,1,2-dimethyl-1-butenyl, 1,2-dimethyl-2-butenyl, 1,2-dimethyl-3-butenyl,1,3-dimethyl-1-butenyl, 1,3-dimethyl-2-butenyl, 1 ,3-dimethyl-3-butenyl,2,2-dimethyl-3-butenyl, 2,3-dimethyl-1-butenyl, 2,3-dimethyl-2-butenyl,2,3-dimethyl-3-butenyl, 3,3-dimethyl-1-butenyl, 3,3-dimethyl-2-butenyl,1-ethyl-1-butenyl, 1-ethyl-2-butenyl, 1-ethyl-3-butenyl,2-ethyl-1-butenyl, 2-ethyl-2-butenyl, 2-ethyl-3-butenyl,1,1,2-trimethyl-2-propenyl, 1-ethyl-1-methyl-2-propenyl,1-ethyl-2-methyl-1-propenyl and 1-ethyl-2-methyl-2-propenyl groups.

The term “aryl,” as used herein, refers to a monovalent aromaticcarbocyclic group of from 6 to 14 carbon atoms. Aryl groups can includea single ring or multiple condensed rings. In some embodiments, arylgroups include C6-C10 aryl groups. Aryl groups include, but are notlimited to, phenyl, biphenyl, naphthyl, tetrahydronaphtyl,phenylcyclopropyl and indanyl. Aryl groups may be unsubstituted orsubstituted by one or more moieties selected from alkyl, alkenyl, halo,haloalkyl, hydroxyl, carboxyl, acyl, acyloxy, amino, alkyl- ordialkylamino, amido, arylamino, alkoxy, aryloxy, nitro, cyano, ester,aryl, or any other viable functional group that is permitted by valenceand does not compromise stability.

The term “alkylaryl,” as used herein, refers to an aryl group that isbonded to a parent -compound through a diradical alkylene bridge,(—CH₂—)_(n), where n is 1-12 and where “aryl” is as defined above.

The term “alkylcycloalkyl,” as used herein, refers to a cycloalkyl groupthat is bonded to a parent compound through a diradical alkylene bridge,(—CH₂—)_(n), where n is 1-12 and where “cycloalkyl” is as defined above.The term “cycloalkylalkyl,” as used herein, refers to a cycloalkylgroup, as defined above, which is substituted by an alkyl group, asdefined above.

Methods

Described herein are methods for breaking a foam, emulsion, or anycombination thereof. The methods can comprise contacting the foam,emulsion, or any combination thereof with a breaking composition. Thebreaking composition can comprise a partitioning agent and optionallyone or more defoamers, demulsifiers, or any combination thereof.

In some embodiments, the foam, emulsion, or any combination thereof canbe formed during an oil and gas operation. In certain embodiments, thefoam, emulsion or any combination thereof can comprise produced fluid(as discussed in more detail below) produced during an oil and gasoperation. In certain embodiments, the produced fluid can comprise botha foam and an emulsion.

The emulsion can comprise a microemulsion. In some embodiments, theemulsion can comprise a Winsor Type I microemulsion. In a Winsor Type Iemulsion, a surfactant forms an oil-in-water microemulsion in theaqueous phase. In some embodiments, the emulsion can comprise a WinsorType II microemulsion. In a Winsor Type II system, a surfactant forms awater-in-oil emulsion in the oil phase. In some embodiments, theemulsion can comprise a Winsor Type III microemulsion. In a Winsor TypeIII system, a surfactant forms a microemulsion in a separate phasebetween the oil and aqueous phases. This phase can be, for example, acontinuous layer containing surfactant, water and dissolvedhydrocarbons.

In some embodiments, the foam, emulsion, or any combination thereof canbe present within equipment associated with an oil and gas operation.For example, the foam, emulsion, or any combination thereof can bepresent within a vessel, pipeline, holding tank, separator, pipe,wellbore, wellhead, or any combination thereof In these embodiments,contacting the foam, the emulsion, or any combination thereof with thebreaking composition can comprise pumping, injecting, pouring,releasing, displacing, spotting or circulating the breaking compositioninto the vessel, the pipeline, the holding tank, the separator, thepipe, the wellbore, the wellhead, or any combination thereof.

In certain embodiments, the foam, emulsion, or any combination can bepresent in a pipe, a pipeline, wellhead, wellbore, or any combinationthereof In some of these embodiments, the methods for breaking the foam,the emulsion, or any combination thereof can comprise injecting thebreaking composition into the pipe, the pipeline, the wellhead, thewellbore, or any combination thereof. The breaking composition can beinjected into the pipe, the pipeline, the wellhead, the wellbore, or anycombination thereof continuously. In other embodiments, the breakingcomposition can be injected into the pipe, the pipeline, the wellhead,the wellbore, or any combination thereof in one or more discreteinjections.

In certain embodiments, the foam, emulsion, or any combination can bepresent in a holding tank, a separator, or any combination thereof. Insome of these embodiments, the methods for breaking the foam, theemulsion, or any combination thereof can comprise injecting the breakingcomposition into the holding tank, the separator, or any combinationthereof. In some of these embodiments, the methods for breaking thefoam, the emulsion, or any combination thereof can comprise injectingthe breaking composition upstream of the holding tank, upstream of theseparator, or any combination thereof. In some of these embodiments, themethods for breaking the foam, the emulsion, or any combination thereofcan comprise injecting the breaking composition downstream of theholding tank, downstream of the separator, or any combination thereof.The breaking composition can be injected continuously. In otherembodiments, the breaking composition can be injected in one or morediscrete injections.

In some embodiments, the breaker composition is combined with the foam,the emulsion, or any combination thereof at varying concentrations. Insome embodiments, the breaker composition is combined with the foam, theemulsion, or any combination thereof at a concentration of 0.01% byvolume or more (e.g., 0.05% by volume or more, 0.1% by volume or more,0.5% by volume or more, 1% by volume or more, 2% by volume or more, 3%by volume or more, or 4% by volume or more). In some embodiments,breaker composition is combined with the foam, the emulsion, or anycombination thereof at a concentration of 5% by volume or less (e.g., 4%by volume or less, 3% by volume or less, 2% by volume or less, 1% byvolume or less, 0.5% by volume or less, 0.1% by volume or less, or 0.05%by volume).

In some embodiments, the breaker composition is combined with the foam,the emulsion, or any combination thereof at a concentration that canrange from any of the minimum values described above to any of themaximum values described above. For example, the breaker composition iscombined with the foam, the emulsion, or any combination thereof at aconcentration from 0.01% to 5% by volume (e.g., from 0.01% to 2% byvolume, from 0.01% to 1% by volume, from 0.01% to 0.5% by volume, from0.05% to 5% by volume, from 0.05% to 2% by volume, from 0.05% tol% byvolume, from 0.05% to 0.5% by volume, from 0.1% to 5% by volume, from0.1% to 2% by volume, from 0.1% to 1% by volume, or from 0.1% to 0.5% byvolume.

Also provided are methods for hydrocarbon recovery that compriseproducing fluids from a conventional or unconventional formation througha wellbore, wherein the produced fluids comprise a foam, an emulsion, orany combination thereof; contacting the produced fluids comprising thefoam, the emulsion, or any combination thereof with a breakingcomposition described herein; and separating a hydrocarbon phase fromthe foam, the emulsion, or any combination thereof. In some embodiments,the method can further comprise preparing the breaking composition, andinjecting the breaking composition.

In some embodiments, the breaking composition can be injected into avessel, a pipeline, a holding tank, a separator, a pipe, a wellbore, awellhead, or any combination thereof. Breaking can occur within thevessel, the pipeline, the holding tank, the separator, the pipe, thewellbore, the wellhead, or any combination thereof

By way of example, FIG. 30 illustrates an example method and system(1000) for hydrocarbon recovery. As shown in FIG. 30, produced fluids(100) comprising an emulsion, a foam, or any combination thereof areproduced from a wellbore (102). The produced fluids can be contactedwith a breaking composition (110) by injecting the breaking compositioninto the stream of produced fluids (100) within the wellhead (104). Abreaking composition inlet valve (108) can be used to control injectionof the breaking composition. An outlet valve (112) can control flow ofthe produced fluid stream (along with the breaking composition) from thewellhead (104) into a conduit or pipe (114). The conduit or pipe (114)can carry the composition downstream to a settling tank (118), where theproduced fluids separate to form an aqueous phase and a hydrocarbonphase. An inlet valve (116) can control flow of the produced fluids intothe settling tank (118). The hydrocarbon phase can then be collectedthrough a hydrocarbon outlet (122), and the aqueous layer can becollected through an aqueous outlet (120).

The breaking composition can be allowed to contact the produced fluidfor varying periods of time depending on the produced fluid. In someembodiments, the breaking composition can be allowed to mix with theproduced fluid for 1 second or more, (e.g., 30 seconds or more, 1 minuteor more, 5 minutes or more, 10 minutes or more, 15 minutes or more, 30minutes or more, or 45 minutes or more). In some embodiments, thebreaking composition can be allowed to mix with the produced fluid for60 minutes or less, (e.g., 45 minutes or less, 30 minutes or less, 15minutes or less, 10 minutes or less, 5 minutes or less, 1 minute orless, 30 seconds or less).

In some embodiments, the breaking composition can be allowed to mix withthe produced fluid for from any of the minimum values described above toany of the maximum values described above. For example, the breakingcomposition can be allowed to mix with the produced fluid for from 1second to 60 minutes, from 30 seconds to 60 minutes, from 1 minute to 60minutes, from 5 minutes to 60 minutes, from 10 minutes to 60 minutes,from 15 minutes to 60 minutes, from 30 minutes to 60 minutes, from 45minutes to 60 minutes, from 1 minute to 30 minutes, from 1 minute to 15minutes, from 1 minute to 5 minutes, from 5 minutes to 30 minutes, orfrom 10 minutes to 30 minutes.

In some embodiments, the hydrocarbon recovery methods described hereincan comprise producing fluid from fractures of an unconventionalsubterranean formation proximate to and in fluid communication with thewellbore. The fractures can be naturally occurring factures, fracturesfrom a fracturing operation, fractures from a refracturing operation, orany combination thereof. The fracturing operation may include hydraulicfracturing, fracturing using electrodes such as described in U.S. Pat.Nos. 9,890,627, 9,840,898, U.S. Patent Publication No. 2018/0202273, orfracturing with any other available equipment or methodology. Therefracturing operation may include hydraulic fracturing, fracturingusing electrodes such as described in U.S. Pat. Nos. 9,890,627,9,840,898, U.S. Patent Publication No. 2018/0202273, or refracturingwith any other available equipment or methodology.

Breaking Compositions

Also provided are breaker compositions. The breaking composition cancomprise a partitioning agent and optionally one or more defoamers,demulsifiers, or any combination thereof. In some embodiments, thebreaking composition can further include one or more additionalcomponents, such as a diluent, a polymer, a pH adjusting agent, achelating agent, a corrosion inhibitor, a biocide, or any combinationthereof.

Partitioning Agents

In some embodiments, the partitioning agent is a fluid. In theseembodiments, the breaking composition can comprise the partitioningagent alone.

In some embodiments, the partitioning agent can have a dielectricconstant of from 1 to 50, such as from 1 to 35, from 1 to 30, from 1 to25, from 1 to 15, from 15 to 35, from 15 to 30, or from 15 to 25.

The octanol-water partition coefficient of a substance X at a giventemperature is represented by P and defined by the equation below

$\lbrack P\rbrack = \frac{\lbrack X\rbrack^{octanol}}{\lbrack X\rbrack^{wate\tau}}$

i.e., the ratio of concentrations of the substance (mole/volume) inoctanol ([X]^(octanol)) and water ([X]^(water)) at equilibrium. Forpurposes of describing the partitioning agents described herein, in someembodiments, the log of the partition coefficient at 25° (log[P]) can befrom −1 to 5, such as from −1 to 3, from −1 to 2, from -1 to 1.5, from-1 to 1, from -1 to 0.8, from -1 to 0.7, from 0.01 to 5, from 0.01 to 3,from 0.01 to 2, from 0.01 to 1, from 0.1 to 5, from 0.1 to 3, from 0.1to 2, from 0.1 to 1, from 0.1 to 0.7, from 0.1 to 0.5, from 0.5 to 5,from 0.5 to 3, from 0.5 to 2, from 1 to 5, from 1 to 3, or from 1 to 2.

The partitioning agent can comprise an alcohol, an ether, a non-ionicsurfactant, or any combination thereof.

In some embodiments, the partitioning agent can comprise an alcohol. Insome embodiments, the alcohol can comprise at least 2 carbons (e.g.,from 2 to 20 carbons, such as from 2 to 12 carbons). In some examples,the alcohol comprises a C2-C10 alcohol, such as a C2-C8 alcohol, a C2-C6alcohol, a C3-C10 alcohol, a C3-C8 alcohol, a C3-C6 alcohol, a C4-C10alcohol, a C4-C8 alcohol, a C4-C6 alcohol, a C5-C10 alcohol, a C5-C8alcohol, or a C5-C7 alcohol, or a C5-C6 alcohol. In some embodiments thealcohol can be branched.

In some cases, the alcohol can comprise a C4-C10 alcohol (branched orunbranched). In some cases, the alcohol can comprise a C4-C8 alcohol(branched or unbranched). In some cases, the alcohol can comprise aC5-C10 alcohol (branched or unbranched). In some cases, the alcohol cancomprise a C5-C8 alcohol (branched or unbranched). In some cases, thealcohol can comprise a C5-C6 alcohol (branched or unbranched). In somecases, the alcohol can comprise a C6-C8 alcohol (branched orunbranched).

Examples of suitable alcohols include hexanol (e.g., n-hexanol),isopropanol, 2-ethylhexanol (e.g., 2-ethyl-1-hexanol),4-methyl-2-pentanol (also known as methylisobutyl carbinol), benzylalcohol, isobutanol, sec-butanol, isobutanol, tert-butanol,pentaerythritol, ethylene glycol, and any combination thereof.

In certain embodiments, the alcohol can comprise 2-ethyl-1-hexanol,4-methyl-2-pentanol, sec-butyl alcohol, isopropanol, isobutanol, or anycombination thereof.

In some embodiments, the partitioning agent can comprise an ether (e.g.,a polyether). For example, in some embodiments, the partitioning cancomprise an alkyl alkoxylate, such as an alkyl alkoxylate defined by theformula below

R¹-Z(BO)-Y(PO)-X(EO)

wherein

R¹ represents a branched or unbranched C₁-C₆ alkyl group or a phenylgroup;

Z represents an integer from 0 to 35, such as from 0 to 30, from 0 to25, from 0 to 20, from 0 to 15, from 0 to 10, or from 0 to 5;

BO represents a butoxy group;

Y represents an integer from 0 to 35, such as from 0 to 30, from 0 to25, from 0 to 20, from 0 to 15, from 0 to 10, or from 0 to 5;

PO represents a propoxy group;

X represents an integer from 1 to 50, such as from 1 to 40, from 1 to30, from 1 to 25, from 1 to 20, from 1 to 15, from 1 to 10, from 1 to 5;from 2 to 50, from 2 to 40, from 2 to 30, from 2 to 25, from 2 to 20,from 2 to 15, from 2 to 10, from 2 to 5; and

EO represents an ethoxy group.

In some embodiments, Z is 0.

In some embodiments, Y is 0. In other embodiments, Y is from 1 to 10(e.g., from 1 to 5).

In some embodiments, both X and Y are 0 (i.e., the alkyl alkoxylate isan alkyl ethoxylate).

In some embodiments, X is from 1 to 10, such as from 2 to 10, 1 to 5, orfrom 2 to 5.

In some embodiments, R¹ is a branched or unbranched C₁-C₆ alkyl group,such as a branched or unbranched C₂-C₆ alkyl group, or a branched orunbranched C₃-C₆ alkyl group.

In some embodiments, the ether can comprise ethylene glycol butyl ether(EGBE), diethylene glycol monobutyl ether (DGBE), triethylene glycolmonobutyl ether (TEGBE), ethylene glycol dibutyl ether (EGDE),aphenol-2EO, phenol-4EO, phenol-1PO-2EO, phenol-2PO-2EO, or anycombination thereof.

In some embodiments, the partitioning agent can comprise a non-ionicsurfactant.

In some embodiments, the non-ionic surfactant can comprise a surfactantdefined by the formula

R²-Z(BO)-Y(PO)-X(EO)

wherein

R² represents a branched or unbranched hydrophobic carbon chain having7-32 carbon atoms;

Z represents an integer from 0 to 35, such as from 0 to 30, from 0 to25, from 0 to 20, from 0 to 15, from 0 to 10, or from 0 to 5;

BO represents a butoxy group;

Y represents an integer from 0 to 35, such as from 0 to 30, from 0 to25, from 0 to 20, from 0 to 15, from 0 to 10, or from 0 to 5;

PO represents a propoxy group;

X represents an integer from 1 to 50, such as from 1 to 40, from 1 to30, from 1 to 25, from 1 to 20, from 1 to 15, from 1 to 10, from 1 to 5;from 2 to 50, from 2 to 40, from 2 to 30, from 2 to 25, from 2 to 20,from 2 to 15, from 2 to 10, from 2 to 5; and

EO represents an ethoxy group.

In some embodiments, Z is 0.

In some embodiments, Y is 0. In other embodiments, Y is from 1 to 10(e.g., from 1 to 5).

In some embodiments, both X and Y are 0 (i.e., the non-ionic surfactantcomprises an alkyl ethoxylate surfactant).

In some embodiments, X is from 1 to 10, such as from 2 to 10, 1 to 5, orfrom 2 to 5.

In some embodiments, the branched or unbranched hydrophobic carbon chainhaving 7-32 carbon atoms can comprise a branched or unbranched C₇ ⁻C₃₂alkyl group, a branched or unbranched C₇-C₃₂ alkylaryl group, or abranched or unbranched C₇-C₃₂ arylalkyl group, or a cycloalkyl group.

Defoamer and Demulsifiers

Optionally, the composition can include one or more defoamers, one ormore demulsifiers, or any combinations thereof. Defoamers anddemulsifiers are known in the art. Examples of such materials includeoil-based defoamers, water-based defoamers, silicone-based defoamers,alkyleneoxy-based defoamers, polyacrylate dofoamers, ketone-baseddefoamers, phenol-formaldehyde resins (acid-catalyzedphenol-formaldehyde resins, base-catalyzed phenol-formaldehyde resins),epoxy resins, polyamines (including polyamine polymers), polyols,di-epoxides, dendrimers, star polymers, zwitterionic surfactants,cationic surfactants, and combinations thereof.

In some embodiments, the breaker composition can comprise an oil-baseddefoamer. Oil based defoamers are known in the art, and include an oilcarrier. The oil carrier can comprise, for example, mineral oil,vegetable oil, white oil or any other oil that is insoluble in thefoaming medium (except silicone oil). Oil-based defoamers can furtherinclude a wax to improve defoaming performance. Typical waxes, include,for example, ethylene bis stearamide (EBS), paraffin waxes, ester waxes,and fatty alcohol waxes. These oil-based defoamers can also includesurfactants to improve emulsification and spreading in the foamingmedium.

In some embodiments, the breaker composition can comprise a water-baseddefoamer. Water-based defoamers are known in the art, and can includeone or more oils, one or more waxes, or any combination thereofdispersed in an aqueous carrier. Examples of suitable oils includemineral oil or vegetable oils. Examples of suitable waxes include longchain fatty alcohols and fatty acid soaps or esters.

In some embodiments, the breaker composition can comprise asilicone-based defoamer. Silicone-based defoamers are known in the art,and can include, for example, a silicone polymer or oligomer (e.g., apolymer or oligomer with a silicon backbone). These might be deliveredas an oil or a water-based emulsion. The silicone compound might alsocomprise a silicone glycol or other modified silicone fluids. In someembodiments, the silicone-based defoamer can a polydimethylsiloxane orderivative thereof. Fluorosilicones can also be used.

In some embodiments, the breaker composition can comprise analkyleneoxy-based defoamer. Alkyleneoxy-based defoamers are known in theart, and can include polyalkylene oxides (e.g., polyethylene glycol,polypropylene glycol, polybutylene glycol, copolymers thereof, andblends thereof). These defoamers can be formulated in oil-basedsolutions, aqueous solutions, or water-based emulsions.

In some embodiments, the breaker composition can comprise apolyacrylate. Polyacrylates (alkyl polyacrylates) are often formulatedin an organic solvent carrier (e.g., a petroleum distillate).

In some embodiments, the breaker composition can comprise a wax. The waxcan include an oxidized polyethylene wax, a microcrystalline wax, ahydroxyl group-containing wax, a paraffin wax, a natural wax, a maleicacid modified wax, an ethylene-vinyl acetate copolymer wax, anethylene-acrylic acid copolymer wax, a Fischer-Tropsch wax, a wood wax,beeswax, palm wax, carnauba wax, montan wax, or any combination thereof.

In some embodiments, the breaker composition can comprise a fatty aciddiamide. The fatty acid diamide can comprise, for example, ethylenebisstearylamide, ethylene bispalmitylamide, ethylene bislaurylamide,methylene bisstearylamide, hexamethylene bisstearylamide, or acombination thereof.

In some embodiments, the breaker composition can comprise a metal soap.Metal soaps can comprise salts of fatty acids having 12 to 22 carbonatoms and metals (alkaline earth metals, aluminum, manganese, cobalt,copper, iron, zinc, nickel, etc.). Examples of metal soaps includealuminum stearate, manganese stearate, stearin, cobalt stearate, copperstearate, iron stearate, nickel stearate, calcium stearate, zinclaurate, magnesium behenate, and combinations thereof.

In some embodiments, the breaker composition can comprise one or more ofthe following: (1) polysiloxanes (silicones), such aspolydimethylsiloxanes (e.g., (CH₃)₃SiO[SiO(CH₃)₂], Si(CH₃)₃),decamethylpentasiloxane, organo-modified silicones,octamethylcyclotetrasiloxane, silicone polyalkyleneoxides, siliconeglycols, polydimethylsiloxanes, silicone co-polymers,trimethylsiloxy-terminated polydimethylsiloxanes,trimethylsiloxy-terminated trifluoropropylmethylsiloxane, alkylarylsiloxanes, polyether modified polysiloxanes, etc.; (2) ethoxylates, suchas octylphenol ethoxylate, nonylphenol ethoxylate, alcohol ethoxylates,etc.; (3) wax-based compounds, such as N,N′-bisstearoylethylendiamine,synthetic wax/mineral oil blends, sorbitan trioleate, etc.; (4)fluoro-substituted compounds, such as fluorosilicones, fluorinatedalcohols, fluoroalkyl alcohol substituted polyethylenes, fluorinatedsubstituted urethanes, perfluoroalkyl methacrylic copolymers,perfluoroalkyl polyurethanes, perfluorobutylethylene,perfluorohexylethyl alcohols, perfluorohexane, perfluorooctane,perfluorohexylethyl methacrylate, polyfluorosulfonic acids,fluoroglycols, fluoroalcohol glycols, perfluoroalkyl methacrylatecopolymers, perfluoroalkylsulfonic acid, fluorinated acrylic copolymers,fluoroethoxylates, etc.; (5) polymers, such as polyethers, alkylcopolymers, alkyl polyglucocides, ethylene oxide copolymers, propyleneoxide copolymers, polyalkyleneglycols, polyether polyols, phosphatepolyether esters, polyethylene glycol copolymers, polypropylene glycolcopolymers, polyacrylates, polypropylenes, etc., (6) mineral oils, suchas activated white oils, paraffin-based mineral oils, etc.; (7)surfactant-type compounds, such as methacrylated mono- and di-phosphateesters, trialkyl phosphate esters, fatty acids, propoxylated/ethoxylatedalcohols, alkoxylated secondary alcohols (e.g., ethoxylated C11-C15secondary alcohols)etc.; (8) sulphur-based compounds, such as polyethersulfates, alkoxylate sulfates, dioctyl sulfosuccinate,alkyldiphenyloxide disulfonate, etc.; (9) succinates; (10) seed oilbased defoamers; (11) long chain chlorinated alkanes, including C20+chlorinated alkanes; (12) cellulose ethers, such as methyl cellulose;(13) ketones, such as methyl isobutyl ketone; and any combinationthereof.

In certain embodiments, the breaker composition can comprise an oligo-and/or polysiloxane (silicone), such as a polydimethylsiloxane (e.g.,(CH₃)₃SiO[SiO(CH₃)₂]_(n)Si(CH₃)₃), decamethylpentasiloxane, anorgano-modified silicone, octamethylcyclotetrasiloxane, a siliconepolyalkyleneoxide, a silicone glycol, a silicone co-polymer, afluorosiloxane (e.g., trifluoropropylmethylsiloxane), atrimethylsiloxy-terminated polydimethylsiloxane, atrimethylsiloxy-terminated trifluoropropylmethylsiloxane, a alkylarylsiloxane, a polyether-modified polysiloxane, or any combination thereof.In one example, the breaker composition can compriseoctamethylcyclotetrasiloxane. In one example, the breaker compositioncan comprise a polydimethylsiloxane.

In certain embodiments, the breaker composition can comprise a ketone,such as methyl isobutyl ketone.

In certain embodiments, the breaker composition can comprise a celluloseether, such as methyl cellulose.

In certain embodiments, the breaker composition can comprise apropoxylated/ethoxylated alcohol.

Additional Components

Optionally, the breaking composition can include one or more additionalcomponents. Examples of suitable additional components include, but arenot limited to, a diluent, a polymer, a pH adjusting agent, a chelatingagent (e.g., EDTA or a salt thereof), a corrosion inhibitor, a biocide,or any combination thereof.

In certain embodiments, the breaking composition can comprise a diluent,such as water, methanol, hydrocarbon solvent (light aromatic naptha,xylene, heptane, octane, etc.), or any combination thereof.

Produced Fluid

In some embodiments, the foam, emulsion, or any combination thereof cancomprise produced fluid (fluid produced from a hydrocarbon-bearingformation). The produced fluid can comprise an aqueous component (water,brine, etc.), a hydrocarbon component (e.g., crude oil), and one or moresurfactants.

In some embodiments, the produced fluid can comprise fluid producedfollowing injection of an aqueous composition into a formation. Theaqueous composition can comprise, for example, an injection fluidintroduced into the formation as part of an enhanced oil recovery (EOR)operation. Examples of EOR operations include, for example, chemicalinjection (sometimes referred to as chemical enhanced oil recovery(CEOR), and which includes, for example, polymer flooding, alkalineflooding, surfactant flooding, conformance control operations, as wellas combinations thereof such as alkaline-polymer flooding oralkaline-surfactant-polymer flooding), a stimulation operation (e.g., asurfactant stimulation operation), microbial injection, and thermalrecovery (which includes, for example, cyclic steam, steam flooding, andfire flooding). In some embodiments, the EOR operation can include analkaline (A) flooding operation, a polymer (P) flooding operation, analkaline-polymer (AP) flooding operation, a surfactant-polymer (SP)flooding operation, an alkaline-surfactant-polymer (ASP) floodingoperation, a conformance control operation, a stimulation operation, orany combination thereof. In other examples, the aqueous composition cancomprise a fracturing fluid. In other examples, the aqueous compositioncan comprise a composition injected for wellbore/near-wellbore cleanupoperations. In these embodiments, the aqueous component of the producedfluid can include one or more components of the injection fluid.

The aqueous component can comprise, for example, produced reservoirbrine, reservoir brine, seawater, fresh water, produced water, water,saltwater (e.g. water containing one or more salts dissolved therein),brine, synthetic brine, synthetic seawater brine, or any combinationthereof.

The produced fluid can further include one or more surfactants. The oneor more surfactants can comprise one or more surfactants injected intothe reservoir as part of an oil recovery application, one or moresurfactants produced in situ within the reservoir (e.g., from reactionof an active oil), or a combination thereof.

In some embodiments, the one or more surfactants can comprise asurfactant package (e.g., a surfactant package that was injected intothe reservoir as part of an oil and gas operation and then produced(along with an aqueous fluid and hydrocarbons), either from the samewell into which the surfactant package was injected or from a nearbyproduction well in fluid communication with the well into the surfactantpackage was injected.

In some embodiments, the surfactant package can comprise a primarysurfactant and optionally one or more secondary surfactants, where atleast one of the surfactants. In some embodiments, the primarysurfactant can comprise an anionic surfactant, and the optional one ormore secondary surfactants can be selected from an anionic surfactant, acationic surfactant, a zwitterionic surfactant, an amphotericsurfactant, a non-ionic surfactant, or any combination thereof. In someembodiments, the primary surfactant can comprise a non-ionic surfactant,and the optional one or more secondary surfactants can be selected froman anionic surfactant, a cationic surfactant, a zwitterionic surfactant,an amphoteric surfactant, a non-ionic surfactant, or any combinationthereof

Examples of anionic surfactants that may be present as a primarysurfactant and/or a secondary surfactant include a hydrophobic tail thatcomprises from 6 to 60 carbon atoms. In some embodiments, the anionicsurfactant can include a hydrophobic tail that comprises at least 6carbon atoms (e.g., at least 7 carbon atoms, at least 8 carbon atoms, atleast 9 carbon atoms, at least 10 carbon atoms, at least 11 carbonatoms, at least 12 carbon atoms, at least 13 carbon atoms, at least 14carbon atoms, at least 15 carbon atoms, at least 16 carbon atoms, atleast 17 carbon atoms, at least 18 carbon atoms, at least 19 carbonatoms, at least 20 carbon atoms, at least 21 carbon atoms, at least 22carbon atoms, at least 23 carbon atoms, at least 24 carbon atoms, atleast 25 carbon atoms, at least 26 carbon atoms, at least 27 carbonatoms, at least 28 carbon atoms, at least 29 carbon atoms, at least 30carbon atoms, at least 31 carbon atoms, at least 32 carbon atoms, atleast 33 carbon atoms, at least 34 carbon atoms, at least 35 carbonatoms, at least 36 carbon atoms, at least 37 carbon atoms, at least 38carbon atoms, at least 39 carbon atoms, at least 40 carbon atoms, atleast 41 carbon atoms, at least 42 carbon atoms, at least 43 carbonatoms, at least 44 carbon atoms, at least 45 carbon atoms, at least 46carbon atoms, at least 47 carbon atoms, at least 48 carbon atoms, atleast 49 carbon atoms, at least 50 carbon atoms, at least 51 carbonatoms, at least 52 carbon atoms, at least 53 carbon atoms, at least 54carbon atoms, at least 55 carbon atoms, at least 56 carbon atoms, atleast 57 carbon atoms, at least 58 carbon atoms, or at least 59 carbonatoms). In some embodiments, the anionic surfactant can include ahydrophobic tail that comprises 60 carbon atoms or less (e.g., 59 carbonatoms or less, 58 carbon atoms or less, 57 carbon atoms or less, 56carbon atoms or less, 55 carbon atoms or less, 54 carbon atoms or less,53 carbon atoms or less, 52 carbon atoms or less, 51 carbon atoms orless, 50 carbon atoms or less, 49 carbon atoms or less, 48 carbon atomsor less, 47 carbon atoms or less, 46 carbon atoms or less, 45 carbonatoms or less, 44 carbon atoms or less, 43 carbon atoms or less, 42carbon atoms or less, 41 carbon atoms or less, 40 carbon atoms or less,39 carbon atoms or less, 38 carbon atoms or less, 37 carbon atoms orless, 36 carbon atoms or less, 35 carbon atoms or less, 34 carbon atomsor less, 33 carbon atoms or less, 32 carbon atoms or less, 31 carbonatoms or less, 30 carbon atoms or less, 29 carbon atoms or less, 28carbon atoms or less, 27 carbon atoms or less, 26 carbon atoms or less,25 carbon atoms or less, 24 carbon atoms or less, 23 carbon atoms orless, 22 carbon atoms or less, 21 carbon atoms or less, 20 carbon atomsor less, 19 carbon atoms or less, 18 carbon atoms or less, 17 carbonatoms or less, 16 carbon atoms or less, 15 carbon atoms or less, 14carbon atoms or less, 13 carbon atoms or less, 12 carbon atoms or less,11 carbon atoms or less, 10 carbon atoms or less, 9 carbon atoms orless, 8 carbon atoms or less, or 7 carbon atoms or less).

The anionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the anionic surfactant can comprise a hydrophobic tailcomprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60,from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32,from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16to 25, from 26 to 35, or from 36 to 45 carbon atoms. The hydrophobic(lipophilic) carbon tail may be a straight chain, branched chain, and/ormay comprise cyclic structures. The hydrophobic carbon tail may comprisesingle bonds, double bonds, triple bonds, or any combination thereof. Insome embodiments, the anionic surfactant can include a branchedhydrophobic tail derived from Guerbet alcohols. The hydrophilic portionof the anionic surfactant can comprise, for example, one or more sulfatemoieties (e.g., one, two, or three sulfate moieties), one or moresulfonate moieties (e.g., one, two, or three sulfonate moieties), one ormore sulfosuccinate moieties (e.g., one, two, or three sulfosuccinatemoieties), one or more carboxylate moieties (e.g., one, two, or threecarboxylate moieties), or any combination thereof.

In some embodiments, the anionic surfactant can comprise, for example asulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, apolysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate,a carboxylate, a dicarboxylate, a polycarboxylate, or any combinationthereof. In some examples, the anionic surfactant can comprise aninternal olefin sulfonate (IOS) other than the olefin sulfonatesdescribed herein, an isomerized olefin sulfonate, an alfa olefinsulfonate (AOS), an alkyl aryl sulfonate (AAS), a xylene sulfonate, analkane sulfonate, a petroleum sulfonate, an alkyl diphenyl oxide(di)sulfonate, an alcohol sulfate, an alkoxy sulfate, an alkoxysulfonate, an alkoxy carboxylate, an alcohol phosphate, or an alkoxyphosphate. In some embodiments, the anionic surfactant can comprise analkoxy carboxylate surfactant, an alkoxy sulfate surfactant, an alkoxysulfonate surfactant, an alkyl sulfonate surfactant, an aryl sulfonatesurfactant, or an olefin sulfonate surfactant.

An “alkoxy carboxylate surfactant” or “alkoxy carboxylate” refers to acompound having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —COO⁻ or acid or salt thereof includingmetal cations such as sodium. In embodiments, the alkoxy carboxylatesurfactant can be defined by the formulae below:

wherein R¹ is substituted or unsubstituted C6-C36 alkyl or substitutedor unsubstituted aryl; R² is, independently for each occurrence withinthe compound, hydrogen or unsubstituted C1-C6 alkyl; R³ is independentlyhydrogen or unsubstituted C1-C6 alkyl, n is an integer from 0 to 175, zis an integer from 1 to 6 and M⁺ is a monovalent, divalent or trivalentcation. In some of these embodiments, R¹ can be an unsubstituted linearor branched C6-C36 alkyl.

In certain embodiments, the alkoxy carboxylate can be aC6-C32:PO(0-65):EO(0-100)-carboxylate (i.e., a C6-C32 hydrophobic tail,such as a branched or unbranched C6-C32 alkyl group, attached to from 0to 65 propyleneoxy groups (—CH₂—CH(methyl)-O— linkers), attached in turnto from 0 to 100 ethyleneoxy groups (—CH₂—CH₂—O— linkers), attached inturn to —COO⁻ or an acid or salt thereof including metal cations such assodium). In certain embodiments, the alkoxy carboxylate can be abranched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate. Incertain embodiments, the alkoxy carboxylate can be a branched orunbranched C6-C12:PO(30-40):EO(25-35)-carboxylate. In certainembodiments, the alkoxy carboxylate can be a branched or unbranchedC6-C30:EO(8-30)-carboxylate.

An “alkoxy sulfate surfactant” or “alkoxy sulfate” refers to asurfactant having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium. In some embodiment, the alkoxy sulfatesurfactant has the formula R-(BO)_(e)-(PO)_(f)-(EO)_(g)-SO₃ ⁻¹ or acidor salt (including metal cations such as sodium) thereof, wherein R isC6-C32 alkyl, BO is —CH₂—CH(ethyl)-O—, PO is —CH₂—CH(methyl)-O—, and EOis —CH₂—CH₂—O—. The symbols e, f and g are integers from 0 to 50 whereinat least one is not zero.

In embodiments, the alkoxy sulfate surfactant can be an aryl alkoxysulfate surfactant. The aryl alkoxy surfactant can be an alkoxysurfactant having an aryl attached to one or more alkoxylene groups(typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which,in turn is attached to —SO₃ ⁻¹ or acid or salt thereof including metalcations such as sodium.

An “alkyl sulfonate surfactant” or “alkyl sulfonate” refers to acompound that includes an alkyl group (e.g., a branched or unbranchedC6-C32 alkyl group) attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium.

An “aryl sulfate surfactant” or “aryl sulfate” refers to a compoundhaving an aryl group attached to —O—SO₃ ⁻ or acid or salt thereofincluding metal cations such as sodium. An “aryl sulfonate surfactant”or “aryl sulfonate” refers to a compound having an aryl group attachedto —SO₃ ⁻ or acid or salt thereof including metal cations such assodium. In some cases, the aryl group can be substituted, for example,with an alkyl group (an alkyl aryl sulfonate).

An “internal olefin sulfonate,” “isomerized olefin sulfonate,” or “IOS”in the context of co-surfactants present in addition to the olefinsulfonates described herein refers to an unsaturated hydrocarboncompound comprising at least one carbon-carbon double bond and at leastone SO₃ ⁻ group, or a salt thereof. As used herein, a “C20-C28 internalolefin sulfonate,” “a C20-C28 isomerized olefin sulfonate,” or “C20-C28IOS” refers to an IOS, or a mixture of IOSs with an average carbonnumber of 20 to 28, or of 23 to 25. The C20-C28 IOS may comprise atleast 80% of IOS with carbon numbers of 20 to 28, at least 90% of IOSwith carbon numbers of 20 to 28, or at least 99% of IOS with carbonnumbers of 20 to 28. As used herein, a “C15-C18 internal olefinsulfonate,” “C15-C18 isomerized olefin sulfonate,” or “C15-C18 IOS”refers to an IOS or a mixture of IOSs with an average carbon number of15 to 18, or of 16 to 17. The C15-C18 IOS may comprise at least 80% ofIOS with carbon numbers of 15 to 18, at least 90% of IOS with carbonnumbers of 15 to 18, or at least 99% of IOS with carbon numbers of 15 to18. The internal olefin sulfonates or isomerized olefin sulfonates maybe alpha olefin sulfonates, such as an isomerized alpha olefinsulfonate. The internal olefin sulfonates or isomerized olefinsulfonates may also comprise branching. In certain embodiments, C15-18IOS may be added to surfactant packages described herein when used forLPS injection fluids intended for use in high temperature unconventionalsubterranean formations, such as formations above 130° F. (approximately55° C.). The IOS may be at least 20% branching, 30% branching, 40%branching, 50% branching, 60% branching, or 65% branching. In someembodiments, the branching is between 20-98%, 30-90%, 40-80%, or around65%. Examples of internal olefin sulfonates and the methods to make themare found in U.S. Pat. No. 5,488,148, U.S. Patent ApplicationPublication 2009/0112014, and SPE 129766, all incorporated herein byreference.

In embodiments, the anionic surfactant can be a disulfonate,alkyldiphenyloxide disulfonate, mono alkyldiphenyloxide disulfonate, dialkyldiphenyloxide disulfonate, or a di alkyldiphenyloxidemonosulfonate, where the alkyl group can be a C6-C36 linear or branchedalkyl group. In embodiments, the anionic surfactant can be analkylbenzene sulfonate or a dibenzene disufonate. In embodiments, theanionic surfactant can be benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt; linear or branched C6-C36alkyl:PO(0-65):EO(0-100) sulfate; or linear or branched C6-C36alkyl:PO(0-65):EO(0-100) carboxylate. In embodiments, the anionicsurfactant is an isomerized olefin sulfonate (C6-C30), internal olefinsulfonate (C6-C30) or internal olefin disulfonate (C6-C30). In someembodiments, the anionic surfactant is a Guerbet-PO(0-65)-EO(0-100)sulfate (Guerbet portion can be C6-C36). In some embodiments, theanionic surfactant is a Guerbet-PO(0-65)-EO(0-100) carboxylate (Guerbetportion can be C6-C36). In some embodiments, the anionic surfactant isalkyl PO(0-65) and EO(0-100) sulfonate: where the alkyl group is linearor branched C6-C36. In some embodiments, the anionic surfactant is asulfosuccinate, such as a dialkylsulfosuccinate. In some embodiments,thebnionic surfactant is an alkyl aryl sulfonate (AAS) (e.g. an alkylbenzene sulfonate (ABS)), a C10-C30 internal olefin sulfate (IOS), apetroleum sulfonate, or an alkyl diphenyl oxide (di)sulfonate.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

R¹-R²-R³

wherein R¹ comprises a branched or unbranched, saturated or unsaturated,cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atomsand an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chaincomprising at least one oxide group selected from the group consistingof ethylene oxide, propylene oxide, butylene oxide, and combinationsthereof; and R³ comprises a branched or unbranched hydrocarbon chaincomprising 2-12 carbon atoms and from 2 to 5 carboxylate groups.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

wherein R⁴ is, independently for each occurrence, a branched orunbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobiccarbon chain having 6-32 carbon atoms; and M represents a counterion(e.g., Na⁺, K⁺). In some embodiments, R⁴ is a branched or unbranched,saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chainhaving 6-16 carbon atoms.

In some embodiments, non-ionic surfactants may be present as the primarysurfactant and/or secondary surfactant. Example non-ionic surfactantsinclude compounds that can be added to increase wettability. In someembodiments, the hydrophilic-lipophilic balance (HLB) of the non-ionicsurfactant is greater than 10 (e.g., greater than 9, greater than 8, orgreater than 7). In some embodiments, the HLB of the non-ionicsurfactant is from 7 to 10.

The non-ionic surfactant can comprise a hydrophobic tail comprising from6 to 60 carbon atoms. In some embodiments, the non-ionic surfactant caninclude a hydrophobic tail that comprises at least 6 carbon atoms (e.g.,at least 7 carbon atoms, at least 8 carbon atoms, at least 9 carbonatoms, at least 10 carbon atoms, at least 11 carbon atoms, at least 12carbon atoms, at least 13 carbon atoms, at least 14 carbon atoms, atleast 15 carbon atoms, at least 16 carbon atoms, at least 17 carbonatoms, at least 18 carbon atoms, at least 19 carbon atoms, at least 20carbon atoms, at least 21 carbon atoms, at least 22 carbon atoms, atleast 23 carbon atoms, at least 24 carbon atoms, at least 25 carbonatoms, at least 26 carbon atoms, at least 27 carbon atoms, at least 28carbon atoms, at least 29 carbon atoms, at least 30 carbon atoms, atleast 31 carbon atoms, at least 32 carbon atoms, at least 33 carbonatoms, at least 34 carbon atoms, at least 35 carbon atoms, at least 36carbon atoms, at least 37 carbon atoms, at least 38 carbon atoms, atleast 39 carbon atoms, at least 40 carbon atoms, at least 41 carbonatoms, at least 42 carbon atoms, at least 43 carbon atoms, at least 44carbon atoms, at least 45 carbon atoms, at least 46 carbon atoms, atleast 47 carbon atoms, at least 48 carbon atoms, at least 49 carbonatoms, at least 50 carbon atoms, at least 51 carbon atoms, at least 52carbon atoms, at least 53 carbon atoms, at least 54 carbon atoms, atleast 55 carbon atoms, at least 56 carbon atoms, at least 57 carbonatoms, at least 58 carbon atoms, or at least 59 carbon atoms). In someembodiments, the non-ionic surfactant can include a hydrophobic tailthat comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less,58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms orless, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atomsor less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbonatoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less,44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms orless, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atomsor less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbonatoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less,30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms orless, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atomsor less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbonatoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less,16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms orless, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atomsor less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atomsor less, or 7 carbon atoms or less).

The non-ionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, thenon-ionic surfactant can comprise a hydrophobic tail comprising from 6to 15, from 16 to 30, from 31 to 45, from 46 to 60, from 6 to 25, from26 to 60, from 6 to 30, from 31 to 60, from 6 to 32, from 33 to 60, from6 to 12, from 13 to 22, from 23 to 32, from 33 to 42, from 43 to 52,from 53 to 60, from 6 to 10, from 10 to 15, from 16 to 25, from 26 to35, or from 36 to 45 carbon atoms. In some cases, the hydrophobic tailmay be a straight chain, branched chain, and/or may comprise cyclicstructures. The hydrophobic carbon tail may comprise single bonds,double bonds, triple bonds, or any combination thereof. In some cases,the hydrophobic tail can comprise an alkyl group, with or without anaromatic ring (e.g., a phenyl ring) attached to it. In some embodiments,the hydrophobic tail can comprise a branched hydrophobic tail derivedfrom Guerbet alcohols.

Example non-ionic surfactants include alkyl aryl alkoxy alcohols, alkylalkoxy alcohols, or any combination thereof. In embodiments, thenon-ionic surfactant may be a mix of surfactants with different lengthlipophilic tail chain lengths. For example, the non-ionic surfactant maybe C9-C11:9EO, which indicates a mixture of non-ionic surfactants thathave a lipophilic tail length of 9 carbon to 11 carbon, which isfollowed by a chain of 9 EOs. The hydrophilic moiety is an alkyleneoxychain (e.g., an ethoxy (EO), butoxy (BO) and/or propoxy (PO) chain withtwo or more repeating units of EO, BO, and/or PO). In some embodiments,1-100 repeating units of EO are present. In some embodiments, 0-65repeating units of PO are present. In some embodiments, 0-25 repeatingunits of BO are present. For example, the non-ionic surfactant couldcomprise 10EO:5PO or 5EO. In embodiments, the non-ionic surfactant maybe a mix of surfactants with different length lipophilic tail chainlengths. For example, the non-ionic surfactant may be C9-C11:PO9:EO2,which indicates a mixture of non-ionic surfactants that have alipophilic tail length of 9 carbon to 11 carbon, which is followed by achain of 9 POs and 2 EOs. In specific embodiments, the non-ionicsurfactant is linear C9-C11:9EO. In some embodiments, the non-ionicsurfactant is a Guerbet PO(0-65) and EO(0-100) (Guerbet can be C6-C36);or alkyl PO(0-65) and EO(0-100): where the alkyl group is linear orbranched C₁-C_(36.) In some examples, the non-ionic surfactant cancomprise a branched or unbranched C6-C32:PO(0-65):EO(0-100) (e.g., abranched or unbranched C6-C30:PO(30-40):EO(25-35), a branched orunbranched C6-C12:PO(30-40):EO(25-35), a branched or unbranchedC₆-30:EO(8-30), or any combination thereof),In some embodiments, thenon-ionic surfactant is one or more alkyl polyglucosides.

Example cationic surfactants include surfactant analogous to thosedescribed above, except bearing primary, secondary, or tertiary amines,or quaternary ammonium cations, as a hydrophilic head group.“Zwitterionic” or “zwitterion” as used herein refers to a neutralmolecule with a positive (or cationic) and a negative (or anionic)electrical charge at different locations within the same molecule.Example zwitterionic surfactants include betains and sultains.

Specific examples of surfactants in that can be present in the producedfluid are shown in the table below.

Injection Fluid Surfactants and Co-Surfactants (in weight percent) 10.1% alkoxylated C6-C18 alcohol 0.02% disulfonate 2 0.2% alkoxylatedC6-C18 alcohol 0.06% disulfonate 3 0.1% alkoxylated C6-C18 alcoholmixture 0.02% disulfonate 4 0.1-1% % alkoxylated C6-C18 alcohol 5 0.09%% alkoxylated C6-C32 Guerbet alcohol 0.03% alkoxylated C6-C16 alcohol0.08% disulfonate 6 0.075% alkoxylated C6-C18 alcohol 0.075% disulfonate7 0.075% alkoxylated C6-C18 alcohol 0.075% betain 8 0.08-0.15%alkoxylated C6-C32 Guerbet alcohol 0.22-0.15% disulfonate 9 0.06-0.14%alkoxylated C6-C32 Guerbet alcohol 0.14-0.06% disulfonate 10 0.06-0.19%alkoxylated C6-C18 alcohol 0.14-0.06% disulfonate 11 0.12% alkoxylatedC6-C32 Guerbet alcohol 0.08% disulfonate 12 0.125% alkoxylated C6-C32Guerbet alcohol 0.125% olefin sulfonate 0.25% Co-solvent 13 0.25%alkoxylated C6-C18 alcohol 0.25% olefin sulfonate 14 0.25% alkoxylatedC6-C32 Guerbet alcohol 0.25% olefin sulfonate 15 0.1% alkoxylated C6-C18alcohol sulfate 0.2% alkoxylated C6-C18 alcohol mix 16 0.12% alkoxylatedC6-C18 alcohol 0.06% olefin sulfonate 0.06% Guerbet alkoxylated sulfate17 0.12% alkoxylated C6-C18 alcohol 0.06% olefin sulfonate 0.06%alkoxylated C6-C18 sulfate 18 0.1% alkoxylated C6-C18 alcohol 0.1%disulfonate 0.1% alkoxylated C6-C18 sulfate 19 0.1% alkoxylated C6-C18alcohol 0.1% olefin sulfonate 0.1% alkoxylated C6-C18 sulfate 20 0.12%alkoxylated C6-C32 Guerbet alcohol 0.06% olefin sulfonate 0.06%alkoxylated C6-C18 sulfate 21 0.1% alkoxylated C6-C32 Guerbet alcohol0.1% disulfonate 0.1% alkoxylated C6-C18 sulfate 22 0.1% alkoxylatedC6-C32 Guerbet alcohol 0.1% olefin sulfonate 0.1% alkoxylated C6-C18alcohol 23 0.12% alkoxylated C6-C32 Guerbet alcohol 0.06% olefinsulfonate 0.06% alkoxylated C6-C18 alcohol 24 0.1% alkoxylated C6-C32Guerbet alcohol 0.1% disulfonate 0.1% alkoxylated C6-C18 alcohol 25 0.1%alkoxylated C6-C32 Guerbet alcohol 0.1% olefin sulfonate 0.1%alkoxylated C6-C18 sulfate

Examples of suitable surfactants are disclosed, for example, in U.S.Pat. Nos. 3,811,504, 3,811,505, 3,811,507, 3,890,239, 4,463,806,6,022,843, 6,225,267, 7,629,299, 7,770,641, 9,976,072, 8,211, 837,9,422,469, 9,605,198, and 9,617,464; WIPO Patent Application Nos.WO/2008/079855, WO/2012/027757 and WO /2011/094442; as well as U.S.Patent Application Publication Nos. 2005/0199395, 2006/0185845,2006/0189486, 2009/0270281, 2011/0046024, 2011/0100402, 2011/0190175,2007/0191633, 2010/004843. 2011/0201531, 2011/0190174, 2011/0071057,2011/0059873, 2011/0059872, 2011/0048721, 2010/0319920, 2010/0292110,and 2017/0198202, and U.S. patent application Ser. Nos. 16/922,999,16/922,993, 16/922,997, 16/923,000 each of which is hereby incorporatedby reference herein in its entirety for its description of examplesurfactants.

EXAMPLES

The examples are set forth below to illustrate the methods and resultsaccording to the disclosed subject matter. These examples are notintended to be inclusive of all aspects of the subject matter disclosedherein, but rather to illustrate representative methods and results.These examples are not intended to exclude equivalents and variations ofthe present invention which are apparent to one skilled in the art.

Efforts have been made to ensure accuracy with respect to numbers (e.g.,amounts, temperature, etc.) but some errors and deviations should beaccounted for. Unless indicated otherwise, parts are parts by weight,percents associated with components of compositions are percent byweight, based on the total weight of the composition including thecomponents, temperature is in ° C. or is at ambient temperature, andpressure is at or near atmospheric.

Example 1 Evaluation of Defoamers vs. 0.15% Surfactant in InjectionBrine Using Overhead Mixer Method

Methods

Defoamers tested: Defoamer 1 is a siloxane-based defoamer, Defoamer 2 isa ketone based defoamer, Defoamer 3 is 4-methyl 2-pentanol, and blends.Test conditions: Temperatures: 22° C., Foam reduction potential definedby fr %=100(ifv−efr)/ify (fR %: foam reduction, ifv: initial foamvolume, efv: ending foam volume), or if heights are used, the definitionis fr %=100(ifh−efh)/(fr %: foam reduction, ifh: initial foam height,efh: ending foam height).

Results and Discussion

Results are shown in FIG. 1-4. FIG. 1 demonstrates that 4-methyl2-pentanol by itself worked as a defoamer for foam created with 0.15%surfactant. Additionally using 4-methyl 2-pentanol with defoamer 1(siloxane-based defoamer) or defoamer 2 (methyl isobutyl ketone)improved the defoaming capability (see FIGS. 3-4). The performance isimproved with a 1:1 blend of 4-methyl 2-pentanol and defoamer 1. The 1:1blend of defoamer 1 and 4-methyl 2-pentanol exhibited strong defoamingbehavior at a concentration of 100ppm as shown in FIG. 4. The ratio inthe blend can be altered to vary the effective concentration at whichthe breaking compositions exhibit strong defoaming behaviors.

Example 2 Evaluation of 4-methyl-2-pentanol, IPA, Non-Ionic Surfactantand Blends as Demulsifiers

Methods

Chemical free oil being studied is mixed with either synthetic waterbased upon its water analysis (containing surfactant, polymer, etc.), ormixed with a field water according to its producing oil/water ratio atthe shear location and temperature (e.g., downhole production).

For the downhole ESP pump area, the mixtures are stirred using alaboratory mixer at 3400-3600 rpm for approximately 2 minutes in a 2000ml plastic beaker. The blades (high shear) of the mixer should be about⅓ from the bottom of the beaker. For other areas with downhole liftingmechanisms, specific mixing should be developed to correctly simulatethe producing shearing conditions. When making emulsion, lots of foamwas generated, therefore 0.01% defoamer was added to break the foambefore test was started (see FIG. 11).

Using the graduated volume lines on the prescription bottles orcentrifuge tubes place 10-100 ml of oil/emulsifier mixture into thebottles. Add the required dosage of treating chemicals to be evaluated.The number of containers used for testing will be x+1, x being thenumber of chemicals being evaluated and the extra bottle being thecontrol. Cap each bottle well and shake 100 times. Place the bottles ina water bath at the required temperature. The water level should behigher than the level of the fluids in the bottle.

Check the oil/water separation half-hourly for up to six hours. Continueuntil there is no change in the separation. Sometimes it may takelonger. Compare the bottles to determine the effect of the demulsifierand/or amount of the demulsifier.

Results and Discussion

Results demonstrate that 4-methyl-2-pentanol, IPA, non-ionic surfactant,or blends of 4-methyl-2-pentanol and non-ionic surfactant can be used asdemulsifiers.

Example 3 Evaluation of Alcohol Based (Partitioning Agent) Emulsion andFoam Breakers

Material:

Formulations tested: Formulation #1: 0.1% alkoxylated C6-C18 alcohol and0.1% disulfonate, Formulation #2: 0.2% alkoxylated C6-C18 alcohol and0.06% disulfonate, Formulation #3: 0.12% alkoxylated C6-C18 alcohol and0.08% disulfonate, Formulation #4: 0.12% alkoxylated C6-C32 Guerbetalcohol and 0.08% disulfonate. Partitioning agents tested: refer to FIG.13.

Demulsifiers (Emulsion Breakers)

Methods

Chemical free oil being studied is mixed with either synthetic waterbased upon its water analysis (containing surfactant, polymer, etc.), ormixed with a field water according to its producing oil/water ratio atthe shear location and temperature (Ex. downhole production).

For the downhole ESP pump area, the mixtures are stirred using alaboratory mixer at 3400-3600 rpm for approximately 2 minutes in a 2000ml plastic beaker. The blades (high shear) of the mixer should be about1/3 from the bottom of the beaker. For other areas with downhole liftingmechanisms, specific mixing should be developed to correctly simulatethe producing shearing conditions. When making emulsion, lots of foamwas generated, therefore 0.01% defoamer was added to break the foambefore test was started (see FIG. 11).

Using the graduated volume lines on the prescription bottles orcentrifuge tubes place 10-100 ml of oil/emulsifier mixture into thebottles. Add the required dosage of treating chemicals to be evaluated.The number of containers used for testing will be x+1, x being thenumber of chemicals being evaluated and the extra bottle being thecontrol. Cap each bottle well and shake 100 times. Place the bottles ina water bath at the required temperature. The water level should behigher than the level of the fluids in the bottle.

Check the oil/water separation half-hourly for up to six hours. Continueuntil there is no change in the separation. Sometimes it may takelonger. Compare the bottles to determine the effect of the demulsifierand/or amount of the demulsifier.

Results and Discussion

C9-11-2.5EO was tested as an emulsion breaker for an emulsion made using0.2% surfactant formulation #1 with 10% oil at both 40° C. and 73° C.Results show that 0.3% of emulsion breaker give promising results within5 minutes at 73° C. (see FIG. 14).

A blend of C9-11 2.5EO and 4-Methyl-2-Pentanol as an Emulsion Breakerwas tested for an emulsion made using 0.2% surfactant formulation #1with 10% oil. The results show that a blend of 0.2% C9-11 2.5EO and0.04% 4-Methyl-2-Pentanol blend work better at 73° C. for 5 minutescompared to the single components. All three samples (0.2% C9-11 2.5EO,0.04% 4-Methyl-2-Pentanol, and the blend 0.2% C9-11 2.5EO and 0.04%4-Methyl-2-Pentanol) work similarly at 40° C. and longer time duration(60 minutes) (see FIG. 15).

4-mthyl-2-pentanol and IPA emulsion breakers were tested individually.FIG. 17 shows that 0.1% of 4-methyl-2-pentanol generated a cleaner pureoil compared to 0.1% IPA.

Results of demulsification using one of the following demulsificationalcohols: ethylene glycol monobutyl ether, ethylene glycol monophenylether, triethylene glycol monobutyl ether, diethylene glycol butylether, propylene glycol butyl ether, phenol-2EO, phenol-4EO,phenol-2PO-2EO, phenol-1PO-2EO, or IBA 5EO for an emulsion including:0.2% Surfactant Formulation #1, 20% Oil #1 at 40° C., and brine #1 areshown in FIGS. 20-25.

FIG. 26 shows the results of demulsification using one of the followingdemulsification alcohols: propylene glycol butyl ether, phenol-4EO,phenol-2PO-2EO, phenol-1PO-2EO, or ethylene glycol monobutyl ether foran emulsion composition including: 0.26% Surfactant Formulation #2, 20%Oil #1 at 40° C. for 10 minutes. The data in FIG. 26 demonstrates thatall the portioning agents tested were effective as demulsifiers.

FIG. 27 shows the results of demulsification using one of the followingdemulsification alcohols: propylene glycol butyl ether, phenol-2PO-2EO,phenol-1PO-2EO, or ethylene glycol monobutyl ether for an emulsionincluding: 0.18% Surfactant Formulation #3, 20% Oil #2 at 40° C. for 10minutes. The data in FIG. 27 demonstrates that all the portioning agentstested were effective as demulsifiers.

FIG. 28 shows, the results of demulsification using one of the followingdemulsification alcohols phenol-2PO-2EO, phenol-1PO-2EO, or ethyleneglycol monobutyl ether for an emulsion including: 0.18% SurfactantFormulation #4, 20% Oil #3 at 40° C. for 10 minutes are shown in FIG.28. The data in FIG. 28 demonstrates that all the portioning agentstested were effective as demulsifiers.

FIG. 32 shows, the results of demulsification using for the followingalcohols oleyl alcohol, ethanol, methanol, PEG400, PEG 200, EGBE, and4-methyl-2-pentanol for an emulsion including: formulation #3 and 20%Oil #3 at 40° C. The data demonstrates that partitioning agents withpartition coefficients (Log K_(ow)) of less than zero or higher than 5are not effective demulsifiers for the formulations described.

Defoamers (Foam Breakers)

Materials

Defoamers tested are described in FIG. 33. Test conditions:Temperatures: 22° C., Foam reduction potential defined by fr%=100(ifv−efr)/ifv (fr %: foam reduction, ifv: initial foam volume, efv:ending foam volume), or if heights are used, the definition is fr %=100(ifh−efh)/ifh (fr %: foam reduction, ifh: initial foam height, efh:ending foam height).

Methods

100 mL of surfactant solution was added to a 1000 ml glass jar andoverhead mixture was placed into the surfactant mixture. Surfactantsolution was mixed at 200 rpm for 1 minute. After setting up the safetyshield surfactant solution was mixed at 2000 rpm for 30 seconds togenerate foam and overhead mixture was stopped. Initial foam height wasrecorded after 3 minutes. After adding target amount of defoaming agent,the solution was mixed at 400 rpm for 1 minute. Foam height was recordedover time. Final reading was recorded after 5 minutes.

Results and Discussion Ethylene glycol monobutyl ether (EGBE) improvedthe performance of Defoamer 3 in a 0.2% surfactant formulation #1 inbrine at room temperature. 200 ppm EGBE and 300 ppm Defoamer 3 had a 50%foam reduction after 2 minutes compared to 500 ppm Defoamer 3 with a 50%foam reduction after 5 minutes.

The compositions and methods of the appended claims are not limited inscope by the specific compositions and methods described herein, whichare intended as illustrations of a few aspects of the claims and anycompositions and methods that are functionally equivalent are intendedto fall within the scope of the claims. Various modifications of thecompositions and methods in addition to those shown and described hereinare intended to fall within the scope of the appended claims. Further,while only certain representative compositions and method stepsdisclosed herein are specifically described, other combinations of thecompositions and method steps also are intended to fall within the scopeof the appended claims, even if not specifically recited. Thus, acombination of steps, elements, components, or constituents may beexplicitly mentioned herein; however, other combinations of steps,elements, components, and constituents are included, even though notexplicitly stated.

By way of non-limiting illustration, examples of certain embodiments ofthe present disclosure are given below.

What we claim is:
 1. A method of breaking a foam, emulsion, or anycombination thereof, the method comprising: contacting the foam,emulsion, or any combination thereof with a breaking composition,wherein the breaking composition comprising a partitioning agent;wherein the partitioning agent has an octanol/water partitioncoefficient ([P]) at 25°, and wherein the log of the partitioncoefficient at 25° (log[P]) is from 0.1 to
 5. 2. The method of claim 1,wherein the partitioning agent has a dielectric constant of from 1 to50, such as from 1 to 35, from 1 to 30, from 1 to 25, from 1 to 15, from15 to 35, from 15 to 30, or from 15 to
 25. 3. The method of claim 1,wherein the partitioning agent comprises an alcohol, an ether, anon-ionic surfactant, or any combination thereof.
 4. The method of claim4, wherein the partitioning agent comprises an alcohol, and wherein thealcohol comprises a branched C₃-C₁₀ alcohol.
 5. The method of claim 4,wherein the partitioning agent comprises an ether, and wherein the ethercomprises an alkyl alkoxylate defined by the formula belowR¹-Z(BO)-Y(PO)-X(EO) wherein R¹ represents a branched or unbranchedC₁-C₆ alkyl group or a phenyl group; Z represents an integer from 0 to35, such as from 0 to 30, from 0 to 25, from 0 to 20, from 0 to 15, from0 to 10, or from 0 to 5; BO represents a butoxy group; Y represents aninteger from 0 to 35, such as from 0 to 30, from 0 to 25, from 0 to 20,from 0 to 15, from 0 to 10, or from 0 to 5; PO represents a propoxygroup; X represents an integer from 1 to 50, such as from 1 to 40, from1 to 30, from 1 to 25, from 1 to 20, from 1 to 15, from 1 to 10, from 1to 5; from 2 to 50, from 2 to 40, from 2 to 30, from 2 to 25, from 2 to20, from 2 to 15, from 2 to 10, from 2 to 5; and EO represents an ethoxygroup.
 6. The method of claim 4, wherein the partitioning agentcomprises a non-ionic surfactant, and wherein the non-ionic surfactantis defined by the formula belowR²-Z(BO)-Y(PO)-X(EO) wherein R² represents a branched or unbranchedhydrophobic carbon chain having 7-32 carbon atoms; Z represents aninteger from 0 to 35, such as from 0 to 30, from 0 to 25, from 0 to 20,from 0 to 15, from 0 to 10, or from 0 to 5; BO represents a butoxygroup; Y represents an integer from 0 to 35, such as from 0 to 30, from0 to 25, from 0 to 20, from 0 to 15, from 0 to 10, or from 0 to 5; POrepresents a propoxy group; X represents an integer from 1 to 50, suchas from 1 to 40, from 1 to 30, from 1 to 25, from 1 to 20, from 1 to 15,from 1 to 10, from 1 to 5; from 2 to 50, from 2 to 40, from 2 to 30,from 2 to 25, from 2 to 20, from 2 to 15, from 2 to 10, from 2 to 5; andEO represents an ethoxy group
 7. The method of claim 3, whereinpartitioning agent comprises hexanol (e.g., n-hexanol), isopropanol,2-ethylhexanol (e.g., 2-ethyl-1-hexanol), 4-methyl-2-pentanol (alsoknown as methylisobutyl carbinol), benzyl alcohol, isobutanol,sec-butanol, tert-butanol, pentaerythritol, ethylene glycol, ethyleneglycol butyl ether (EGBE), diethylene glycol monobutyl ether (DGBE),triethylene glycol monobutyl ether (TEGBE), ethylene glycol dibutylether (EGDE), propylene glycol butyl ether, ethylene glycol monophenylether, phenol-2EO, phenol-4EO, phenol-1PO-2EO, phenol-2PO-2EO, a C8-C16alkyl ethoxylate, or any combination thereof.
 8. The method of claim 1,wherein the breaking composition further comprises one or moredefoamers, demulsifiers, or any combination thereof
 9. The method ofclaim 8, wherein the one or more defoamers, demulsifiers, or anycombination thereof comprise an oil-based defoamer, a water-baseddefoamer, a silicone-based defoamer, an alkyleneoxy-based defoamer, apolyacrylate defoamer, a ketone-based defoamer, a phenol-formaldehyderesins such as an acid-catalyzed phenol-formaldehyde resin or abase-catalyzed phenol-formaldehyde resin, an epoxy resin, a polyaminessuch as a polyamine polymers, a polyol, a di-epoxide, a dendrimer, astar polymer, a zwitterionic surfactant, a cationic surfactant, or acombination thereof.
 10. The method of claim 9, wherein the one or moredefoamers, demulsifiers, or any combination thereof comprise an oligo-and/or polysiloxane (silicone), such as a polydimethylsiloxane (e.g.,(CH₃)₃SiO[SiO(CH₃)₂]_(n)Si(CH₃)₃), decamethylpentasiloxane, anorgano-modified silicone, octamethylcyclotetrasiloxane, a siliconepolyalkyleneoxide, a silicone glycol, a silicone co-polymer, afluorosiloxane (e.g., trifluoropropylmethylsiloxane), atrimethylsiloxy-terminated polydimethylsiloxane, atrimethylsiloxy-terminated trifluoropropylmethylsiloxane, a alkylarylsiloxane, a polyether-modified polysiloxane, or any combination thereof.11. The method of claim 1, wherein the foam, the emulsion, or anycombination thereof is present on or within equipment associated with anoil and gas operation.
 12. The method of claim 11, wherein the foam, theemulsion, or any combination thereof is present in a separator, andwherein the method comprises injecting the breaking composition into theseparator, injecting the breaking composition upstream of the separator,injecting the breaking composition downstream of the separator, or anycombination thereof.
 13. The method of claim 12, wherein the foam, theemulsion, or any combination thereof is present in a pipe, in apipeline, in a wellhead, or any combination thereof, and wherein themethod comprises injecting the breaking composition into the pipe, intothe pipeline, into the wellhead, or any combination thereof
 14. Themethod of claim 13, wherein the method comprises continuous injectingthe breaking composition.
 15. The method of claim 1, wherein the foam,the emulsion, or any combination thereof comprises a produced fluid. 16.The method of claim 15, wherein the produced fluid comprises an aqueouscomponent, a hydrocarbon component, and one or more surfactants.
 17. Themethod of claim 16,wherein the one or more surfactants comprises one ormore non-ionic surfactants, one or more anionic surfactants, one or morecationic surfactants, one or more zwitterionic surfactants, or anycombination thereof.
 18. The method of claim 17, wherein the one or moresurfactants comprise one or more non-ionic surfactants, and wherein theone or more non-ionic surfactants comprises a branched or unbranchedC₆-C32:PO(0-65):EO(0-100), such as a branched or unbranchedC6-C30:PO(30-40):EO(25-35), a branched or unbranchedC6-C12:PO(30-40):EO(25-35), or a branched or unbranched C6-C30:EO(8-30).19. The method of claim 17, wherein the one or more surfactants compriseone or more anionic surfactants, and wherein the one or more anionicsurfactant comprise one or more of the following: a branched orunbranched C6-C32:PO(0-65):EO(0-110)-carboxylate, such as a branched orunbranched C6-C30:PO(30-40):EO(25-35)-carboxylate, a branched orunbranched C6-C12:PO(30-40):EO(25-35)-carboxylate, or a branched orunbranched C6-C30:EO(8-30)-carboxylate; a C8-C30 alkyl benzene sulfonate(ABS); an internal olefin sulfonate (IOS); an isomerized olefinsulfonate; an alfa olefin sulfonate (AOS), a sulfosuccinate surfactant;an alcohol sulfate surfactant; an alkoxy sulfate surfactant; asurfactant defined by the formula belowR¹-R²-R³ wherein R¹ comprises a branched or unbranched, saturated orunsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32carbon atoms and an oxygen atom linking R¹ and R²; R² comprises analkoxylated chain comprising at least one oxide group selected from thegroup consisting of ethylene oxide, propylene oxide, butylene oxide, andany combination thereof; and R³ comprises a branched or unbranchedhydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5carboxylate groups; a surfactant defined by the formula below

wherein R⁴ is, individually for each occurrence, a branched orunbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobiccarbon chain having 6-32 carbon atoms; and M represents a counterion; orany combination thereof.
 20. A breaking composition comprising apartitioning agent and one or more defoamers, demulsifiers, or anycombination thereof, wherein the partitioning agent has an octanol/waterpartition coefficient ([P]) at 25°, and wherein the log of the partitioncoefficient at 25° (log[P]) can be from 0.1 to 5, such as from 0.1 to 3,from 0.1 to 2, from 0.1 to 1.5, from 0.1 to 1, from 0.1 to 0.8, or from0.1 to 0.7.